bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracturing-to-Production Integrated Completion Sensitivities for Horizontal Well Design in the Vaca Muerta Shale
Authors: Pichon S. , Cafardi F. , Cavazzoli G. D. , Diaz A. , Lederhos M. R.
Published: May 2017

The boom of organic shale plays has revealed the critical need to correctly size hydraulic facture treatments to achieve commercial success in those reservoirs. The right balance must be found between the cost of fracturing and the additional production achieved by increasing the formation-to-wellbore contact area. Such a balance is formation specific and depends on the reservoir properties and local well completion costs. This paper examines a wide range of completion scenarios to evaluate the relationship between hydraulic fracture design, production, and well profitability using numerical simulations to guide completion of horizontal wells in the Vaca Muerta shale.

Evaluation of the interaction between completion and production requires an integrated approach including both static (petrophysics, geomechanics, and the characteristics of natural fractures) and dynamic (reservoir fluid, conductivity degradation, and reservoir pressure) properties. The hydraulic fracture geometry is determined using a state of the art simulator that models the physical mechanisms of elastic deformation, leakoff, proppant transport, and the interaction between hydraulic and natural fractures. The explicit description of the hydraulic fracture geometry ensures that any variation in the completion design is consistently taken into account. Hydraulic fracture geometry is then directly fed into a reservoir simulator to evaluate the anticipated production. The resulting production profile is then input to an economic model to assess the profitability of the proposed scenario. The model is based on the latest understanding of the Vaca Muerta shale and is calibrated by reproducing the average historical production of the play.

A sensitivity study is performed to investigate the impact of each completion parameter. Proposed sensitivities consider a large range of completion design parameters for a horizontal well, such as the type and volume of fracturing fluid and proppant, number and spacing of perforation clusters, and staging strategies. The sensitivity analysis covers more than 60 completion scenarios over 550 fracturing stages and 1,600 individual hydraulic fractures. All the simulation cases are combined in a database to quantitatively evaluate the impact of completion design over the hydraulic fracture dimensions and production, and highlight its main contributors. Total volume of proppant per well and perforation cluster spacing show a good correlation with production. This production increase can be linked with an increase of the propped surface highlighting the need for the right balance in between fracturing fluid viscosity to enhance transport and the proppant concentration to compensate for total treatment volume. The results of this study provide practical guidelines for optimizing completion of horizontal wells in the Vaca Muerta shale.
Green Fracturing Technology of Shale Gas: LPG Waterless Fracturing Technology and its Feasibility in China
Authors: Jin F. , Shunyuan Z. , Bingshan L. , Chen C. , Kedi M.
Published: May 2017

As a kind of water saving and green fracturing methodology, the innovative LPG fracturing fluid system that is developed by Gasfrac is known for its low density, viscosity and surface tension, making satisfying achievements in McCully Gasfield in Canada. However, it has not been applied by scale in China and requires further analysis.

The LPG fracturing technology was analyzed technically and its physical properties were studied, including viscosities and surface tensions of water, butane and propane within various temperature ranges. A LPG fracturing phase control diagram and a fluid capillary pressure diagram were drafted. Production data of many shale gas wells in McCully block were analyzed to accomplish the fracturing flowback formula. The economical analysis of the LPG fracturing technology was completed, including the overall cost of slickwater fracturing fluid and water treatment, as well as the overall cost of LPG fracturing fluid and its integrated devices.

The slickwater fracturing fluid has been widely used in China to exploit shale gas, which wastes a lot of water and does harm to environment. The LPG fracturing technology utilizes liquefied petroleum gas as the fracturing fluid that mainly consists of propane with ethane, butane, propylene and some additives, so it is harmless to formation. Compared with conventional hydraulic fracturing, the LPG fracturing fluid is mixed with chemical additives when being pumped and it becomes a kind of viscous fluid like gel, so that proppant particles may be evenly distributed in it and they don't deposit along fractures. Besides, fractures are higher and the production life of gas wells is improved. Propane mixes with natural gas completely and it may reduce the oil's viscosity after contacting it. Therefore, there is no need of flowback and water treatment procedure. Injected in a closed loop, the LPG fracturing fluid is operated via a remote computer and monitored by sensors distributed in the operation area, so that LPG leakage risk is reduced and the fracturing operation may be carried out safely.

Shale gas is being widely exploited in Sichuan Province, which is located at the source of Yangtze River. In Ordos Basin limited water sources make it very costly to prepare conventional fracturing fluids. The slickwater fracturing fluid is cheaper than the LPG fracturing fluid, while water treatment costs more. All in all, LPG fracturing technology shall be recommended in China that suffers from severe environmental risks and water scarcity.
RMFinder 2.0: An Improved Interactive Multi-Criteria Scenario Reduction Methodology
Authors: Meira L. A. , Coelho G. P. , Silva C. G. , Schiozer D.J. , Santos A. S.
Published: May 2017

This paper presents an extension of the RMFinder technique, previously proposed to identify representative models (RMs) within the decision-making process in oil fields. As there are several uncertainties associated with this decision-making process, a large number of scenarios are supposed to be analyzed, so that high-quality production strategies can be defined. Such broad analysis is often unfeasible, so techniques to automatically identify RMs are particularly relevant. The original RMFinder does not consider the individual probability of each RM, which may not be accurate when the risk curves of the problem are estimated. Therefore, a mechanism to calculate the individual probability of each RM was developed here, together with a graphical way to visualize different proposals of RMs. To automatically identify the optimal probability of each RM, this new version of RMFinder minimizes the deviation between the risk curves generated with the selected RMs and the original risk curves of the problem. The graphical approach automatically exhibits, in a single page per solution, the RM dispersion in the scatter plots, the resulting risk curves and the differences between attribute-level distributions. This helps the decision makers to visualize and compare different sets of RMs. The proposed methodology was applied to a small synthetic problem and to three reservoir models based on real-world Brazilian fields: (i) UNISIM-I-D, a benchmark case based on the Namorado field; (ii) UNISIM-II-Dβ, a benchmark case based on a highly fractured pre-salt carbonate reservoir; and (iii) ST001a, a highly heterogeneous heavy oil offshore field. The obtained sets of RMs were evaluated by experts and considered appropriate to the studied problems, being adopted as the standard models in the following steps of the decision-making process to define the production strategies under uncertainties.
Assessment of Economic Viability of Various Field Development Strategies
Authors: Igbokwe L. , Hossain M.
Published: May 2017

This paper presents a comprehensive perspective for comparing field development strategies (i.e. setting up oil field for production) by outlining a simple approach to help the integrated asset team in making decision on which method would be most appropriate. The field development options considered were natural depletion, water injection, gas injection, and water alternate gas (WAG).

UBED field was discovered in 1974, water depth is 130 m with initial reservoir pressure of 446 bars and 35,681,991 m3 estimated oil initially in-place (OIIP). Preliminary assessment using the material balance indicated about 25% ultimate recovery. Each scenario was optimized for maximum hydrocarbon recovery at the lowest cost per barrel by optimizing of wells, and critical gas saturation (i.e. 0% and 10% respectively). Economic analysis was performed using NPV, profitability index, payback period, and IRR on the cases. For each scenario, a plateau rate of 15% is maintained per year at a production rate of 3500 m3/d as benchmark.

The various economic impacts on the project were determined and the results are presented. Results shows that estimated ultimate recoveries (EUR) were 30.9%, 53%, 37.2% and 53.5% for natural depletion, water injection, gas injection, and water alternate gas injection schemes respectively. The best production option for UBED reservoir lies between water injection and WAG injection. The comparison between the two scenarios shows that WAG is less costly and to develop the reserves while recovery, and profits are very high. Production plateau can also be sustained economically for longer period with shorter pay back on investment. In addition, WAG shows better EUR, a shorter production plateau of about 4% increases in over the water injection. This increase was not offset by profit indices, and payback. In this scenario, a gas compressor was installed which resulted in an increased capital expenditure (CAPEX).

The revenues, expenses, and profits from each scenario are compared for the various development options at the end of the section and a proposed plan is selected based on economic parameters. The comparative economic assessment of the UBED field case in this study adequately addresses critical cost parameters relevant to field development studies, and integrated comparison of profitability indicators from which reliable economic decision can be reached.
Real-Time Surveillance and Optimization of Wells with Intelligent Completions in Ecuador
Authors: Villa M. B. , Liang W. , Gottumukkala V. , Gornescu B. C. , Contreras C.
Published: May 2017

Producing from mature oil fields in Ecuador introduces many reservoir challenges, including multizone oil production and artificial lift demands due to high water cut. Traditionally, dual-string completions with sliding sleeves and dual electrical submersible pumps (ESP) were used to access different reservoir layers and obtain back allocation with standard surface well testing.

One operator adopted intelligent completions (IC) well design with flow control valves and gauges that allowed single-string configurations, reducing the number of ESPs required to address lift issues. Production is commingled downstream from the flow control valves that independently adjust production from each layer. Unlike traditional dual completions, this intelligent completion is versatile and simplifies workovers, precluding the need to pull the entire lower completion.

High-frequency real-time gauge data acquired from intelligent completions is applied intermittently to analyze pressure build tests and estimate reservoir properties.

The paper outlines the pilot project implemented to realize the value of the intelligent completions by monitoring production parameters (layer flow rates, water cut, and productivity index) through 24/7 surveillance and periodic optimization using a software solution.

The software was connected to a real-time data source that gathered data from intelligent completions (downhole pressure and temperature gauges, and valve position sensors) and automatically calculated drawdown, fluid gradients, etc., in real time. It enabled users to study trends in real-time and historical data, and set alarms for unexpected well production variations like increasing water cut, scaling, and slugging. During the pilot project, optimization cases were performed and presented to the production team with recommendations about choke positions to achieve the highest oil production.

Production engineers responded to the changes by modifying ESP frequency, changing valve choke positions, and cycling valves to optimize production and improve operational efficiency.
Determination of Load Effects on a Sealbore Packer with Floating Seal Assemblies During a Dynamic Underbalanced Perforation
Authors: Magri J. L. , Scudino-Borges R. P. , Jeronimo-Junior E.
Published: May 2017

Combining tubing-conveyed perforation techniques with completion isolation valves and sealbore packers enables multiple entries to the reservoir, with different production strings. It also avoids recurrent use of killing fluids because the packer and isolation valve mechanically protect the reservoir. The perforation technique also results in a dynamic underbalance, creating tunnels as clean as possible. However, it may generate a huge pressure differential between the upper packer annulus and the inner string below the packer, which causes the upper string to exert extra compressive force on the packer.

The presented workflow relies on new software solutions to ensure successful and safe operations. The dynamic underbalance perforation's effects are simulated in appropriate software, which are then integrated with tubing design analysis suites. The combination of both results provides a more conservative and complete methodology of possible events occurring in the completions, enabling the extent of the loads to be safely evaluated and specifically addressed. The analysis indicates possible job modification strategies, such as increase of packer to gun length, changing the perforation charges loading arrangement, modifying the production string seal length, or installation of a stiffer upper completion string.

For the present work, a study case was thoroughly explained, where excessive load of the packer could occur in result of the differential pressure across the elements and floating seal units. The above mentioned design changes are explored individually through the workflow and the results discussed. These changes can reduce the forces acting on the packer, prevent major mechanical failures, and ensure the job stays within operational limits.
Surveillance and Initial Results of an Existing Polymer Flood: A Case History From The Rayoso Formation
Authors: Martino L. A. , Fernandez Righi E. , Gandi S. , Thompson A. , Giaquinta A. D.
Published: May 2017

A semi-regional 3D model of the Rayoso Formation in the Neuquén basin, Argentina, has been used to predict that several millions of barrels of additional oil can be recovered by polymer flooding in six fields of YPF S.A. As a result of static and dynamic modelling, two polymer flood pilots in separate fields have been approved. The first pilot started polymer injection in July 2016, while the second one is expected to commence in late 2017. This paper describes the approaches currently used and proposed for surveillance to ensure that the pilot objectives are met and to demonstrate the feasibility of field-scale application of polymer flooding across the Rayoso formation.

A multidisciplinary integrated surveillance plan has been implemented to prevent the pilot from failing due to avoidable causes. Data on polymer quality monitoring, tracer surveys, interwell tracers, fall-off tests, and production and injection review are regularly fed into simulation models. We describe how this is achieved while limiting additional staffing and equipment costs.

The pilot test discussed here lies in a multi-reservoir field where oil production is commingled with two deeper reservoirs. In order to make the oil production response to polymer injection directly detectable, the central producing wells in the pilot were recompleted to produce only from the Rayoso formation. Since there was no practical possibility to do the same for the second-line (offset) production wells, geochemistry techniques were used to identify the oil produced from each formation and thus estimate incremental produced outside of the pilot area.

Although the Rayoso formation has been exploited for more than 30 years, only recently has it been given priority as a production target. At the beginning of the study, several major uncertainties exisited that could adveesely affect the potential success of polymer flooding in this reservoir, especially those regarding the initial and remaining oil saturation in the formation.

As a result of the appraisal and surveillance plan applied, key project uncertainties were addressed or assessed by monitoring potential deviations of a set of variables from the project prognosis in real time.

Interwell tracers and pressure fall off tests during the baseline waterflood provided data to reduce the uncertainty in the presence of possible flow barriers in the pilot area. Frequent production tests and continuous well bottomhole pressure data enabled calibration of the simulation model and to predict the behavior of the declining phase of the baseline waterflood with resasonable confidence. A single well polymer injectivity test with back flow, performed in one of the pilot injectors, showed that the selected polymer at the target concentration was not significantly degraded in the reservoir.
Overhauling KPI Drilling Performance Trough RT Operations Integration Center
Authors: Fierro-Herrera M. , Romero-Chacin D. , Schmidt A. , Erives-Gonzalez J. L. , Dick H. P. , Dorantes-Garcia-Barzanallana A. E. , Amundsen S. , Guedes de Carvalho R. , Lopez J. C. , Escobedo-Flores M. , Basso-Mora M. A. , Kim A. , Hoil-Marrufo G. , Garcia H.
Published: May 2017

Real Time monitoring centers had focused on risk management, historic data review, trend analysis and wellbore stability awareness. In this abstract the transformation of a Drilling Real Time Monitoring Center is described, identifying new processes which, with no additional resources, developed a supplementary branch of real time monitoring: drilling performance optimization. The usage of daily received data and the potentiation of the RT Monitoring Software allowed to identify Removable Lost Time (RLT), optimizing drilling crews tripping time and connection times. A concerted effort to measure rigs suppliers through unified KPIs and daily performance reports which fomented competence and performance improvement. This step change delivered an OIC: Operations Integration Center which overhauled Mexico Land Drilling Performance creating a step change in daily operations with direct benefits to oilfield real time practices.
Impact of Clay type on SAGD Performance Part I: Microscopic Scale Analysis of Clay-SARA Interactions in Produced Oil
Authors: Kar Taniya , Hascakir Berna
Published: May 2017

The impact of non-swelling clays on Steam-Assisted Gravity Drainage (SAGD) performance was studied in this work. Two SAGD experiments were conducted on a Canadian bitumen by preparing the reservoir rocks with two different non-swelling clays; kaolinite (SAGD1) and kaolinite (90 wt%) and illite (10 wt%) (SAGD2). Change in clay type from kaolinite to a mixture of kaolinite and illite resulted in 15 wt% lower cumulative oil recovery. The role of clays and their interaction with crude oil fractions; namely Saturates, Aromatics, Resins and Asphaltenes (SARA fractions), on process performance was investigated through control experiments under optical and scanning electron microscopy. Pseudo blends of clays and SARA fractions revealed that kaolinite-asphaltenes interaction in SAGD1 occurs at steam condition, however, the same interaction happens for kaolinite-illite mixture at liquid water condition. It has been observed that while kaolinite-asphaltenes interaction is a direct interaction, 10 wt% illite addition to clay (SAGD2) causes an indirect interaction. This indirect interaction occurs due to mainly aromatics-clays association. Clays in SAGD2 were observed to be carried inside asphaltenes clusters. Since aromatics are soluble in asphaltenes, initially a black colored microscopic image was obtained. Upon the evaporation of aromatics, it has been observed that clays still preserve their original white color, however, stuck in asphaltenes clusters. Thus, our results concluded that not only heavy and polar fractions of crude oil, but also non-polar fractions may play an important role in oil displacement during SAGD.
High Resolution Dynamic Modelling to Revitalize a Mature Oil Field in a Low Oil Price Scenario
Authors: Perez D. G. , Pedersen G. A. , Lehu R. E. , Thompson A. , Morettini E.
Published: May 2017

The current low oil price scenario makes it increasingly critical to build robust business cases, to model uncertainty and to identify the most efficient and economically viable scenarios for any field development or redevelopment strategy.

The purpose of this paper is to present a multi-scale reservoir modelling approach to assess economic viability for the development of an EOR project in an adverse oil price scenario. We present an on-going polymer injection project in a brown oil field in the Western Flank of the Golfo San Jorge Basin in southern Argentina as case study for this methodology. Productive interval consists of a 1000 meters-thick low net-to-gross fluvial succession, in the Cretaceous Bajo Barreal Formation. The field produces a ~100 cp oil with very low recovery factor and a watercut of 94%, after 25 years of waterflood.

The need for high resolution models is validated by a cell size sensitivity analysis on polymer injection simulations. We verified that almost 50% error on oil incremental forecasts by polymer injection is obtained if 50 × 50 m cells were used. Therefore, combining purpose-built dynamic models in different scales and economic evaluation we support the on-going execution of the EOR pilot project. Several static/dynamic models are built at different scales (from 10 km to 100 m) to capture depositional trends and model stratigraphic and sedimentary heterogeneities. We evaluate different physical aspects of the polymer injection process with specifically designed numerical simulations at appropriate resolution. We think that detailed modelling and data acquisition are highly profitable decisions even in current challenging economic scenario, aiming at reducing uncertainty and strengthening business cases. Indeed, laboratory and field measurements, identification of critical variables, and high resolution modelling proved to reduce forecast uncertainty and strengthen business case economic indicators.
Hydraulic Fracture Propagation Modeling in a Homogeneous Elastic Media with Leakoff
Authors: Morales-Matamoros D. , Kanaun S. , Chi-Chim M.
Published: May 2017

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

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

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

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

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

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

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

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

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 >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

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

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

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.