bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Authors: Kristensen Morten , Ayan Cosan , Chang Yong , Lee Ryan , Gisolf Adriaan , Leonard Jonathan , Corre Piere-Yves , Dumont Hadrien 
Published: June 2014

Abstract
Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall.
We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe.
This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.
Successful Extended Injection Test for Obtaining Reservoir Data in a Gas-Oil Shale Formation in Mexico
Authors: Araujo O. , Lopez-Bonetti E. , Garza D. , Salinas G. 
Published: June 2014

Abstract
This paper presents the results from a diagnostic fracture extended injection test performed in a well completed in the first oil shale reservoir confirmed in Mexico, which is situated in the Upper Jurassic in the Burgos basin in the northern part of the country.
The test was executed in an exploratory horizontal well during the first stage, perforated with abrasive hydra-jetting, and reservoir properties had been previously set with the correlation information logs. Usually performed before treatment(s), the primary objective of a diagnostic fracture injection test (DFIT) is to estimate parameters that provide fracture information critical both to designing the fracturing treatment and the characterization of the formation, as well as to obtain more reliable information for production engineering. Compared to other methods for the diagnostic of reservoir properties, the economic value that DFIT can provide is particularly effective in formations with ultralow permeability (K &lt;0.1 md). These injection-falloff tests, which include small volumes of fluid pumped into the formation and use few resources to obtain data, proved to be an essential tool to understand some reservoir characteristics which can provide the information necessary for an optimal fracture design and warn of issues that might be experienced during the stimulation execution.
This paper evaluates all aspects related to the pressure falloff and how important values, such as permeability and reservoir pressure, were obtained using analysis in real time from the wellsite.
Advancements in Powered Rotary Steerable Technologies Result in Record-Breaking Runs
Authors: Jerez H. , Tilley J. 
Published: June 2014

Abstract
Drilling operators continually experience increasing pressure to achieve all objectives safely and at the lowest cost. Powered rotary steerable systems (RSS), applied within the correct drilling environment, can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can decrease drilling costs.
Using through motor telemetry (TMT) technology, a wired motor with a hollow rotor and flex shaft, allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole tools. A conductor passes power and communication through the motor to operate and steer the RSS. The wired power section uses a uniform wall thickness stator design that reduces heat production and retention. It also delivers higher rev/min and torque directly to the RSS and bit. Using the TMT powered RSS not only has improved ROP, but has also mitigated stick-slip vibration and reduced NPT. The NPT improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string torque variations, casing wear, and rig equipment failures.
Early planning and risk assessment have also been key. Experience across the globe, both on and offshore, are presented to show the benefits of integrating advanced drilling technologies, such as TMT powered RSS and real-time downhole measurements with effective planning, to reap tangible benefits from drilling optimization.
With improved performance as a result of increased torque capacity and bit speed, and reduction of the stick-slip mechanism, this new motor-driven rotary steerable technology has delivered superior performance and improved ROP in challenging medium and hard formations. After more than 10,000 drilling hours and nearly half a million feet drilled, TMT powered RSS technology is setting new records and exceeding benchmarks by bringing greater horsepower to the rock destruction process with longer runs and higher ROPs.
Injection Leakage Detection in Mature Fields Using Data-Driven Models
Authors: Moreno G. A. , Garriz A. E. 
Published: June 2014

Abstract
The estimation of injected water distribution in mature fields is a key factor to optimize oil recovery. Ab initio models are hard to implement for surveillance proposes because of uncertainties in the input data and high computational cost. However, some data-driven models, such as the capacitance-resistance model with dynamic connectivities, are able to encode the emergent physical behavior of a mature field in a simple but still realistic description that can be calibrated using production and completion data. In this work we apply this technique to a big mature waterflood, Chihuido de la Sierra Negra, consisting of over 1500 wells. We show that the method is useful to calculate a set of possible problematic injectors based on the sum of estimated connectivity factors. Injection loss is identified when the total connectivity for a given injector is lesser than one. The numerical scheme allows an automatic history match within minutes yielding to the best estimates for the model parameters. The results of the analysis are compared with well surveys, revealing remarkable effectiveness in leakage diagnosis. This work demonstrates that the Capacitance-Resistance Model with Dynamic Connectivities paves the way for real-time surveillance of water distribution in mature fields based on production and completion data.
Velocity Modeling During Interpretation: A Case Study in the South Region of Mexico
Authors: de la Torre J. A. , Sevilla H. , Saucedo Reyes H. , Bejarano G. 
Published: June 2014

Abstract
This case study in the South Region of Mexico explains a complex modeling workflow from structural seismic attributes to regional velocity models that include different geological structures like shale diapirs, listrict regional faults and a salt body intrusion which represent vertical and lateral dramatic changes of velocity, making difficult to define units and boundaries in a formal sense, increasing the uncertainty and decision making risk and affecting the drilling operations even with lessons learns.
Hence, we present a seismic attributes case with velocity modeling to allow a complete and dynamic integration of geological interpretation and the velocity modeling building.
The solution approach consists of a combination of new generation structural seismic attributes in order to extract and highlight geobody structures with a structural framework modeling; the structural framework can be linked to seismic interpretation geobody, allowing the model to be built on the fly in a "Modeling While Interpreting" workflow facilitating the creation of structurally correct interpretation.
Then, the population of velocity is conducted in a combination of the 3D grid base modeling approach and the analysis of the velocity distribution especially inside the shale geobody obtaining a more accurate velocity variation.
Fully Compositional Integrated Subsurface-Surface Modeling: Carito Production Unit Case
Authors: Escalona J. , Figueroa A. , Lopez L. 
Published: June 2014

Abstract
A fully compositional integrated subsurface-surface model for the Production Unit Carito was develop to support a future exploitation plan that considers the maintaining of the oil production plateau and an aggressive infill drilling for the next 3 years. These issues make imperative an integrated asset modeling that conduct and help the reservoir management, decision making and accurate estimation of additional facilities capabilities.
The Production Unit Carito comprises two of the most important fields located to the east of Venezuela: El Carito and Mulata. These fields present deep and complex reservoirs with an unconventional column of fluids, showing a marked compositional gradient which cover from an initially undersaturated gas condensate at the top of the structure to an undersaturated black oil zone toward the base. The OOIP is about 7, 000 MMSTB and the current oil production rate reaches 230 MSTB/D. A secondary recovery process was implemented over 12 years ago, based on the injection of approximately 1, 000 MMSCF/D of natural gas.
Because of prevailing reservoir pressure conditions, the increasing volumes of produced gas has led that some points of the surface facilities reach their operational limits. Furthermore, the first of all, 187 well models in compositional format were built, performing sensitivities to define the multiphase flow correlations for vertical pipe and for critical/subcritical flow in chokes, considering dynamic gradients and production tests. A network model, which comprises more than 800 Km of lines, was also built in compositional mode honoring line sizes, lengths, elevation changes and connection points, reducing the number of nodes to decrease computing time. The robust numerical simulation model comprises more than 300, 000 active cells, and represents the most reliable characterization of the reservoirs. Each model was firstly initialized and isolated run to discard internal inconsistency. Finally, the full integration was done considering the sand face on the wells as the coupling point.
The integrated subsurface-surface simulation allowed predicting the behavior of reservoir production taking into account the constraints of the surface facilities. In this way, it was reduced the uncertainty of forecasts, and were identified limitations at surface facilities. It was also possible to determine accurately the details of the hydrocarbons streams at different pressure stages of the network, with an excellent matching with the oilfield production data.
Analysis of Inflow-Control-Valves Shutdown Effects in Well Production and Economics
Authors: Botechia V. E. , Barreto C. E. , Schiozer D. J. 
Published: June 2014

Abstract
Inflow control valves (ICV) can be used to add flexibility to petroleum production operation. They can be used as a reaction of an undesired event (reactive control), like water breakthrough, but they can also be used to prevent or to delay these events (proactive control). Proactive control can be an efficient form to control intelligent wells. However, the benefits of proactive control require an appropriate study to avoid premature decisions that lead to suboptimal results. This paper focuses on the evaluation of the effects caused by ICV operation and its impact on long term field production and cash flow, giving support to tools or equipment to apply proactive controls (use of seismic, sensors etc.). The main objective is to show when possible benefits of a proactive operation can be reached. An inverted five-spot model, representing a specific region of a reservoir, is used to verify the effects of ICV operation, with different production and injection constraints. The results show that proactive control with ICV can, in some cases, improve the performance of the field by increasing oil production and decreasing water production, however, this kind of control is not always profitable. The results also show that ICV shutdowns can significantly alter the behavior of the wells.
Integrated Modeling of a Highly Structural and Complex Reservoir Where the Normal Modeling Rules Do Not Apply, Cerro Fortunoso.
Authors: Thompson Anthony , Garriz Abel , Manestar Gaston , Vocaturo Griselda , Consoli Vanesa , Giampaoli Pablo 
Published: June 2014

Abstract
Cerro Fortunoso is a field with excess of 30 years production history which lies in Mendoza Province, Argentina. A study was undertaken to establish if the existing five injection well waterflood pilot could be expanded to encompass the rest of the 240+ well field and that the necessary investment for facilities could be justified.
A detailed look at the field quickly shows why waterflood has only been tried in a very limited fashion. The Cerro Fortunoso anticline is an asymmetric, west verging structure orientated NNE-SSW and affected by different kinds of faults located in a fold and thrust belt. The anticline geometry is affected by low and high angle reverse faults generating an eastern flank that dips up to 80° at the central part of the fold.
An initial static model representing the structural complexity and the 17 cycle high resolution stratigraphic framework was constructed. However interpretation of RFT data demonstrated that flow was controlled by thin sandstones lying in the same high order cycles but which were pressure isolated from each other, hence for secondary recovery it was necessary to understand the areal extent and connectivity of these sand bodies. Additionally the very high angle of dip and the heterogeneous fluvial reservoir meant that a sandstone body could plausibly connect with a number of different sandstones on a neighboring well, leading to a situation where different correlations schemes were plausible.
This paper details how the uncertainty in the correlation of the sand bodies was reduced by integration of static and dynamic data. A number of correlation scenarios were constructed in the static model and subsequently evaluated by dynamic testing against the production and pressure data. Through iterations, a dynamic model was subsequently constructed that matched production and pressure history and in which it was possible to determine which sands were more critical to the success of any waterflood.
The geological understanding developed demonstrated that sandstone throughout the field had similar connectivity and petrophysical characteristics to those in the waterflood pilot area. It was also seen that if the sandstones were to be more discontinuous or to have a lower net-to-gross than modeled, historical production could not be matched in dynamic simulation. This methodology has demonstrated the potential to recover significant incremental hydrocarbons by waterflooding the whole field.
Selection of Optimum Completion Intervals Based on NMR Calibrated Lithofacies
Authors: Lafournère Jean-Paul , Dutan Jorge , Hurtado Jorge , Suter Andreas , Bringer Florent , Naranjo Michelle , Bourge Jean-Pierre , Gozalbo Eduardo 
Published: June 2014

Abstract
The Shushufindi field is located in the Oriente basin of Ecuador. The field was discovered in 1972 and is sparsely developed with about 200 wells covering an area of approximately 400 km2. An initial lithofacies characterization based on capillary pressures, pore throat size distribution, and log derived total porosities and permeabilities has provided a coherent grouping for the reservoir types that matched in over 92% of the wells.
The importance of pore throat size in the initial lithofacies characterization has spurred the use of nuclear magnetic resonance (NMR) logs. NMR laboratory measurements on core samples complement the characterization with continuously calibrated pore body size derivations. Furthermore extensive whole core studies have shown that the pore throat size has a substantial impact on the initial oil saturation. Failures to respect this later point had previously generated disappointing oil production results. The challenge for the subsurface and engineering team is to take advantage of a lithofacies-based method to determine appropriate completion intervals and generate reliable production predictions.
Open hole wireline log measurements of derived pore bodies size show a good correlation to NMR laboratory measurements on plugs when grouped within the initial lithofacies characterization. These data are used to provide a calibrated continuous pore body size curve based on the NMR binned porosities, and using the inferred initial oil saturation, to estimate the flow capacities for each lithofacies. This approach provides adequate support for selecting the reservoir rock with the best flow capacity, thereby optimizing the well completion. In thin beds where the vertical resolution of standard density and NMR logs is insufficient to discriminate the best facies a modified method has been developed. Very high resolution imaging has been coupled with flushed zone (Rxo) measurements and high frequency dielectric dispersion log to identify the potential production.
This paper presents a lithofacies characterization enhancement methodology using NMR derived pore body size as implemented in the Shushufindi field, the results to date, its impact on the selection of completion intervals, and the resulting improvement in production from this technique.
A New Implementation of a Directional Surface Hole as an Economical Solution for Reaching the Shallower Reservoirs in Wells of the Orinoco Oil Belt in Venezuela
Authors: Trejo E. , Machado P. , Aguilar V. , Garcia W. , Bonalde A. 
Published: June 2014

Abstract
The expansion of the heavy oil recovery campaign in Venezuela led by the National Oil Company and its partner has placed more attention on developing shallow reservoirs in the Orinoco Oil Belt. Here, the main challenge is to economically drill horizontal shallow wells at less than 1300 ft TVD, and with more than 5000 ft of lateral extension. To reach these reservoirs, the well path is normally planned with high build rates in the intermediate phase reaching ≥9°/100 ft before and after the tangent section that is required to place the pumping system.
When drilling using a mud motor, the high build rates planned for the intermediate section can result in even higher localized dogleg severities (DLS) as drilling switches between sliding and rotating. This creates several problems when drilling and completing the horizontal section, for example, poor transfer weight to the bit while sliding and torque and drag situations, which can make it impossible to reach the entire horizontal section planned with this BHA.
Progressive cavity pumps (PCPs) are preferred for use in the Orinoco Oil Belt as they are more efficient and economical. However, high dogleg severities are not recommended for production systems using PCPs. Most PCP designers recommend placing the equipment at doglegs of &lt;7°/100 ft to increase service life and avoid premature intervention due to excessive wear.
To optimize design and extend the life of production equipment, a new mechanical well design was developed where the deviation of the hole starts in the 16-in. top hole using a directional BHA configuration with a mud motor. This configuration drilled successfully and safely; making possible to reach the entire planned horizontal section and complete it with an optimum production system.
By applying this new design and using conventional directional technologies, it is possible to drill the entire horizontal section and use the same completion system used in the rest of the area. This is an important cost savings because the custom directional technology can be used to reach the entire horizontal section but completion maintenance costs won't increase. In addition, we avoid deferred production costs due to shutting down the wells.
Automating a Comprehensive Methodology for Evaluation, Selection, and Sizing of Sand Control Methods in Fields With Sand Problems_A Case Study
Authors: Oliveira Gomes D. G. , Carruyo Villalobos J. F. , González Castaño E. R. 
Published: June 2014

Abstract
Evaluation of fields with sand problems is a complex activity that involves different disciplines of study and the review of several information, which is mainly related to well logs and reports, allowing for each of the studied wells the selection and sizing of recommended sand control methods. Automation of these calculation, with the use of a software originally designed to process reservoir static model, allows the use of all available well logs in the field to identify zones having the optimum rock properties to apply a specific sand control method, and to develop maps that shows the sized sand control methods applicable to each layer of the reservoir. Additionally, these results lead to more broadly assess all existing completions in this field and explain their success or failure over time.
Currently, several reservoirs in Venezuela and worldwide present sand issues, where in some cases the consensus for used sand control methods in the field have been established by trial and error over time, but in the case of a successful sand production reduction, a wrong selection and sizing of the filter media can bring problems from flow production restriction to plugging by fines, both affecting the well productivity or even the well life.
The need for integrated studies to evaluate these fields, covering all technical aspects involved, raises the need to automate calculation process performed for each well in the study, so that in this way is possible to maximize number of studied wells and thereby, obtain more comprehensive and detailed results to start, in a shorter time and with much more available information, the evaluation and analysis of the reservoir in terms of sand control completions.
Results of a case study are presented, and are related to a shallow weak consolidated reservoir in western Venezuela.