bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.