bluuebunny/crossref_metadata_2025_split huggingface dataset:
Applying Big Data Analytics to Detect, Diagnose, and Prevent Impending Failures in Electric Submersible Pumps
Authors: Gupta Supriya , Saputelli Luigi , Nikolaou Michael 
Published: September 2016

Abstract
More than 90% of producing oil wells require some form of artificial lift for pumping production fluids to the surface (Bates, Cosad et al. 2004). The electrical submersible pump (ESP) is widely used and is currently the fastest growing form of artificial-lift pumping technology. About 15 to 20 percent of almost one million wells worldwide produce oil with the help of ESPs (Breit and Ferrier 2008). ESPs are usually considered more efficient and reliable among all oilfield lift systems and enable recovery of hydrocarbon fluids from greater depths at higher temperatures while handling a range of viscosities, gas-liquid ratios, and solids production. Over the years, the most common concern of operators using ESPs in their assets has been high workover costs and inadequately low system run life (Vandevier 2010). It is often observed that ESP performance declines gradually and reaches the point of service interruption due to a number of factors such as high gas volumes, high temperature, and corrosive environments. Should an ESP fail, the financial impact would be substantial, in terms of both lost production and replacement or intervention costs. Given the high cost of an ESP failure, operators are increasingly investing in real-time surveillance sytems to monitor ESP performance using downhole measurements and raise alarms in case of abnormal events such as trippings or failures. However, such systems are reactive in nature, i.e. action is taken after an event occurs. Consequently, there is a need and an opportunity to utilize the large amount of data being collected in real time from ESP operations, and to create solutions that advance from a reactive to a more proactive approach that would ideally detect issues well in advance, diagnose causes, and suggest corrective action. This paper offers such an approach. Specifically, a data-driven analytical solution is proposed to proactively monitor and transform vital statistics related to ESP performance into actionable information using multivariate statistical techniques for dimensionality reduction and pattern recognition. This real-time framework combines engineering principles with mathematical models to detect impending problems long before they occur, diagnose potential causes, and prescribe preventive action. This can safeguard ESP operations and increase uptime, extend ESP life expectancy, reduce intervention costs, and optimize production.
Integrated Dynamic Simulation Leads to Successful Start-Up of Inactive Wells Through Rigless Operations
Authors: Yusuf Rahel , Kumar Thakur Kapil , Ahmed Jama Ali 
Published: September 2016

Abstract
During a well start-up, fluid distribution within the well changes from a segregated phase (gas-oil-water) column to a flowing three phase mixture. For this transition to be successful, the well has to overcome the additional hydrostatic head associated with the phase segregation. Depending on the well trajectory, flowline pressure, reservoir pressure and watercut, the start-up process can be challenging for some wells as an improper bean-up procedure can result in a situation where the pressure driving force across the well is not able to overcome the hydrostatic head imposed by the liquid column. This can result in a failed start-up and, for such wells, a correct bean-up strategy is important to ensure successful start-up.
In this study, an integrated dynamic multiphase simulator is used to investigate the flow and pressure transients during the start-up of an inactive horizontal oil well which encountered start-up problems after a well intervention job to shut-off high watercut zones.
Sensitivities using dynamic simulations for different start-up procedures showed that the well could be successfully started-up by opening the well at the maximum available beansize and ensuring stable flow thereafter by keeping the bean-back above a threshold beansize. The successful well start-up procedure developed using dynamic simulations was applied in the field and resulted in additional oil production. This study demonstrates the significance of dynamic simulations in optimizing well start-up procedures. In this case, this resulted in major incremental revenue for the operator with more than 1000 BOPD added to overall production. Further, the successful start-up procedure devised using a transient multiphase simulator resorted only to well fluids routing and choke manipulation without the need for expensive rig operations and CAPEX/OPEX expenditure.
Reservoir Fluid Geodynamics; The Link Between Petroleum Systems and Production Concerns Relating to Fluids and Tar Distributions in Reservoirs
Authors: Mullins Oliver C. , Primio Rolando Di , Zuo Julian Y. , Uchytil Steve , Mishra Vinay K. , Dumont Hadrien , Pfeiffer Thomas , Achourov Vladislav V. , Pomerantz Andrew E. , Forsythe Jerimiah , Betancourt Soraya S. , Elshahawi Hani 
Published: September 2016

Abstract
Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.
A Universal Model of Water Flow Through Nanopores in Unconventional Reservoirs: Relationships Between Slip, Wettability and Viscosity
Authors: Wu Keliu , Chen Zhangxin , Xu Jinze , Hu Yuan , Li Jing , Dong Xiaohu , Liu Yuxuan , Chen Mingjun 
Published: September 2016

Abstract
Understanding and controlling flow of the water confined in nanopores has tremendous implications in theoretical studies and industrial applications. Here we propose a universal model for the confined water flow based on a conception of effective slip, which is linear sum of true slip, only depending on wettability, and apparent slip, caused by the spatial variation of the confined water viscosity as a function of wettability as well as nanopores dimension. Results by the model show that the flow capacity of the confined water is 10−1~107 times of those calculated by no slip Hagen-Poiseuille equation for nanopores with various wettability, in agreement with 47 different cases from the literature. This work may shed light on the controversy over the increase or decrease in flow capacity from the MD simulations and experiments, and guide to tailor the nanopores structure for modulating the confined water flow in many engineering fields, including nanomedicine, water purification, energy storage as well as the flowback of fracture fluid in petroleum industry.
Evaluation of Preformed Particle Gels Penetration into Matrix for a Conformance Control Treatment in Partially Open Conduits
Authors: Imqam Abdulmohsin , Aldalfag Ahmed , Wang Yanling , Bai Baojun 
Published: September 2016

Abstract
Preformed particle gels (PPGs) serve as a conformance control agent and have been used widely to control excess water production through conduits, fractures or fracture-like features. This paper ranks the parameters that impact PPG resistance to water flow in partially opened conduits and provides methods to minimize PPG penetration effect on matrices. Experiments were conducted to examine the effect of brine concentration, PPG injection pressure, back pressure, and matrix permeability on PPG resistance to water flow through conduits and PPG penetration to matrix. PPGs were swelled in different concentration brines and were injected into the conduits at a few designed injection pressures. Results show PPG resistance to water flow may have been the result of gel particle accumulation into conduits or gel filter cake formation in rock matrix or both. Their resistance increased when they were injected at high pressure. In contrast to PPGs placement through fully opened conduits, PPGs were not produced from the partially opened conduits; however, PPGs formed a filter cake on the surface of the matrix. Gel particles penetration into the matrix were only a few millimeters deep, and their penetration into to the matrix depended on matrix permeability, gel strength, and injection pressure drop across the core.
Temperature Transients Affect Reservoir Pressure Estimation During Well Tests - Case Study and Model
Authors: Maizeret Pierre-David , Sidorova Maria , Lipovetsky Tatiana 
Published: September 2016

Abstract
This paper discusses how the pressure measured by the downhole gauges during a drillstem test (DST) is affected not only by hydrostatic, friction or kinetic energy pressure losses, but also by changes in temperature. In oil wells, the bottomhole temperature is decreasing when the pressure is building up after a flow period. The change in temperature is inducing a change in the wellbore fluid density, itself affecting the bottomhole pressure. Most numerical simulators modeling flow in pipes do not take into account this effect, as it is not significant for low to moderate productivity wells. In high productivity wells however, the temperature change can affect drastically the bottomhole pressure measured above the reservoir and the pressure can even decrease at the end of a static period. A mathematical model is presented to compute the pressure drop caused by the nonisothermal effects and can be used to correct the measurements. Field examples are discussed to illustrate this effect and recommendations are made on how new technology can improve pressure measurements during well tests.
In order to measure the effects on the pressure measurements due to the position of the gauges in the DST string, two gauge carriers were run in some well tests in deepwater wells offshore Brazil, one at the level of the tester valve, and one below packer, as deep as possible in the test string. The gauges could transmit data with a wireless telemetry system that allowed the operator to monitor in real-time the pressure changes and the difference between the two sets of gauges.
In high permeability wells, using the uncorrected pressure measured with a gauge 50 to 100 m above the reservoir as is typically the case, can result in a wrong productivity index and at times, in uninterpretable results. Locating pressure gauges as close to the reservoir as possible is crucial in highpermeability reservoirs, to minimize the measurement errors, but also to avoid misinterpretations when an obstruction forms below the tester valve. With the new wireless telemetry systems, it is possible to monitor in realtime gauges mounted below the packer, much closer to the perforations than the standard gauges placed at the level of the tester valve, thus avoiding taking wrong decisions during the test.
A long pressure transient test could be uninterpretable because the gauges are located at the wrong depth. Ideally, the pressure gauges should be placed in front of the perforations but it is not always possible. Therefore, non-isothermal effects on pressure measurements during a well test needs to be clearly understood and taken into account when designing and interpreting well tests, particularly in high productivity reservoirs.
Nanocapsules for Controlled Release of Waterflood Agents for Improved Conformance
Authors: Johnson Leah M. , Norton Chasity A. , Huffman Nicolas D. , Mecham Jeffrey B. , Rothrock Ginger D. 
Published: September 2016

Abstract
The use of polymer gels for water shutoff is a valuable approach to control water production and improve conformance. One polymer gel system, partially hydrolyzed polyacrylamide in combination with Cr(III), shows utility for water shutoff within the near wellbore region. Deeper placement of this polymer gel system within the reservoir is challenging, owing to rapid reaction rates of the gel precursors that prohibits propagation and in-depth placement. The use of a nano-delivery vehicle (i.e., nanocapsule) to contain and shield Cr(III) from the reservoir for a defined time could enable deeper placement and effectiveness of the polymer gel treatment. By protecting the Cr(III) from the polyacrylamide, the gelation is postponed until programmed release of the Cr(III) deeper within the reservoir. Herein, we present feasibility studies that demonstrate the capacity to encapsulate Cr(III) into sub-micron nanocapsules using an inverse miniemulsion technique. Nanocapsules exhibit distinct core-shell morphology, measuring between approximately 200 nm to 500 nm in diameter, depending on the formulation. Laboratory studies successfully demonstrate the encapsulation of Cr(III) within the particles and suggest the potential for delayed release of the Cr(III) cargo. The nanocapsules tolerate simulated reservoir conditions, including high temperatures (50°C) and concentrated salinity. A stable core-shell nanocapsule designed to encapsulate Cr(III) crosslinker via a technically feasible and scalable encapsulation method addresses the requirement for improved waterflood applications and the ability to reach deeper into high permeability zones deep in the reservoir. The technological advancements presented in this paper support a novel approach and hold great potential for controlled delivery of chemistries targeted for the oilfield.
Inferring Interwell Connectivity Using Production Data
Authors: Tian Chuan , Horne Roland N. 
Published: September 2016

Abstract
A key issue of waterflooding is to locate the injectors so as to optimize the production from producers. To resolve the issue in the face of geologically variation, we need to understand how the production is influenced by the injection, in other words, the connectivity between the producers and injectors. It would be very useful for us to build a reservoir scale network based on the connectivity and perform reservoir analysis using such a network representation, without reference to a reservoir simulation model that is obliged to make assumptions about the geology.
The work shown in this paper was organized into three parts. First, a modified Pearson's correlation coefficient was proposed as a new connectivity definition based on the correlation between injection and production histories. Next, machine learning based multiwell testing was applied to learn the correlation between producer rate features and injector pressures, which provided a validation to the connectivity estimated by modified Pearson's correlation coefficient. Last, a connectivity based network was proposed as an abstract reservoir representation. A series of network analyses can be performed on the established network, e.g. reservoir compartmentalization by detecting the strongly connected clusters in the network.
The proposed methodologies were applied on both synthetic and real data sets. The connectivity was shown to be able to capture the injectors' influence on producers, and was verified by comparing with the true reservoir model and results from tracer tests. The target injectors with high influence on production were identified easily as the ones connected to multiple producers, information that can be used to guide a better waterflooding operation.
Optimizing Well Patterns for Various Geologic Facies Models
Authors: Hollander Avi , Qi Kevin , Ershaghi Iraj 
Published: September 2016

Abstract
Control of wasteful water injection is an important objective in optimizing waterfloods. Inefficiencies related to vertical sweep efficiency and some plausible corrective measures have been adequately covered in the literature. The purpose of this paper is to focus on areal sweep efficiency for a single layer assuming that, if needed, sub-zoning steps to minimize thief zone effects from other layers have been previously implemented.
In general, it is essential to minimize bypassing of otherwise recoverable oil and reduce channeling. The presence of geometrically complex connected and disconnected sand bodies creates challenges in maximizing areal sweep efficiency and in designing and managing efficient fluid injection projects. Traditionally, the practice in the industry has been to use simplified well spacing patterns. Many poor waterfloods started this way, using classical geometries without recognizing or honoring the inherent complexities of sand bodies in terms of competitive units with different hydraulic transmissivities.
We present a study highlighting the impact of improper well pattern selections that place injection wells in very high permeability channels. It can result in early elevated water-oil ratios and associated recovery losses because of a limited sweep of low permeability areas. This study is primarily focused on inappropriate placement of uniform well patterns in the presence of reservoir scale channel sands.
For a single layer, our study shows that the early rise in WOR and the deviation from linearity on the semi-log plot of WOR vs. cumulative oil is often indicative of early channeling and successive breakthroughs from tighter intervals. These scenarios can serve as monitoring tools to realign and relocate injectors that may have been unknowingly placed in high permeability channels.
A Fully 3-D, Multi-Phase, Poro-Elasto-Plastic Model for Sand Production
Authors: Wang Haotian , Sharma Mukul M. 
Published: September 2016

Abstract
This paper presents a coupled reservoir-geomechanics model with multi-phase fluid flow for sand production prediction in a weakly consolidated formation. Sanding criteria are based on a combination of tensile and shear failure from Mohr-Coulomb theory and strain-hardening/softening. Once the failure criteria are met, an algorithm for entrainment of the sand based on the calculation of hydrodynamic and other forces is implemented to predict sand erosion. The flow of two immiscible slightly compressible fluids coupled with geomechanics has also been modeled. This allows us to account for relative permeabilities and capillary pressure dependent cohesion and rock residual strength.
The onset of sanding and the sand production rate have both been simulated for open-hole and cased-hole completions under different flow conditions. The model utilizes a dynamic mesh which removes the grid blocks of sand that have failed and meet the erosion criteria. This allows the proper boundary condition to be applied to the sand face as sand is continuously produced. Good agreement with experimental observations is obtained for both the onset of sand production and the rate of sand production when simulations are conducted for open-hole completions. The post-failure elasto-plastic properties of the sand are seen to play an important role in determining the extent of sand production and the shape of the cavity created. In addition, the effect of wellbore pressure drop rate, controlled by choke adjustment, has been studied on the sanding risk. Multi-phase fluid flow effects, including relative permeability and capillary cohesion, are also shown to significantly impact the sand production.
Data Management Requirements for Supporting Digital Energy Initiatives
Authors: Kozman Jess B. 
Published: September 2016

Abstract
As the concepts of "Big Data" and "Predictive Analytics" have made their way along the hype curve (Gartner, 2015), digital energy initiatives have seen many attempts to practically employ these methologies for business gain. In many cases these initiatives have generated less than the expected benefit, or in some cases, failed to answer the business question being addressed. A review of case studies shows that in many cases, the failure was not due to a lack of data, but rather due to fundamental problems with how the data was curated before being applied to the analytic solution. In this paper, we describe and apply industry best practices from the broader data management community which can improve the quality and value of data and information in support of digital energy initiatives
Unconventional Cyclone Gas Lift Completion for Offshore Wells of Cambay Basin: A Smart Completion to Optimize Production and Well Intervention
Authors: Singh Kumar Abhishek , Sarkar Prakhar , Praleya Pranshu , Sai Gogineni Sudarsan 
Published: September 2016

Abstract
The downtime of oil and gas industry dictates the review of Vortex Technology that has been used oil and gas industry for many intentions. An innovative application of this technology is in conjunction with gas lifts that not only organise the three phase flow of oil, gas and water but also optimize production. We can rather say that this technology has the potential to produce unconventional completions. The application of downhole cyclone boosted production many folds. The application of downhole cyclone presented an interesting idea for production optimization in gas lifts and well intervention schemes. The versatile nature of tool dictates its application in CTU and horizontal wells as flow control devices. The downhole cyclone will certainly provide a way forward to cut risks in offshore projects. Therefore, this innovation is certainly a permanent solution to all problems.