bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Kalman Filter to Predictions of Pore Pressure While Drilling
Authors: Bektas Evren , Miska Stefan Z. , Ozbayoglu Evren M. , Yu Mengjiao , Takach Nicholas , Velazquez-Cruz David , Shahri Mojtaba Pordel 
Published: September 2015

Abstract
Accurate formation pore pressure prediction is the most important requirement for safe and effective drilling. It essentially contributes to the reduction of drilling risks and provides cost-effective drilling of wells. Even though there are methods that rely on well logs, seismic data and effective stress models to predict pore pressure, there is no model available for real-time pore pressure prediction ahead of the bit.
This study explains how to design and apply a steady-state Kalman filter to predict real-time formation pore pressure optimally by combining outputs from both Eaton's model and from Logging While Drilling (LWD). The objectives of this study are to minimize the noise on pore pressure predicted from well logs (or LWD) measurements and to compute the next estimate of pore pressure ahead of bit using only the most recent measurement.
Data obtained from well logs usually have noise measurements. The noise measurements lead to changes of the results acquired from well logs. Therefore, uncertainties occur on the estimated pore pressure. The designed Kalman filter is a recursive data processing algorithm to produce optimal estimate of pore pressure ahead of the drill bit. The estimates tend to be more refined than those based on measurements from well logs alone.
First, Eaton's method, which is one of the most widely used pore pressure prediction methods, was modeled and represented in the state-space form required for Kalman Filter modeling. Parameters used in the Kalman Filter algorithm were also identified in state-space form. A computer code to implement the designed Kalman filter algorithm has been developed. Additionally, field data were used to evaluate the performance of the proposed algorithm.
Based on the results, it is concluded that Kalman filter can be a very effective tool for detecting overpressure zones to avoid drilling problems before entering such zones.
The most important achievement is that the developed algorithm can be used as a design tool in offshore and onshore drilling operations along with real-time LWD data to optimally estimate the formation pore pressure of the next interval ahead of the bit during the drilling operation.
Short-Term Production Operation Management: Continuous Application of an Innovative Integrated Production Optimization Tool
Authors: Scaramellini Sara , Cerri Paolo , Bianco Amalia , Masi Silvia 
Published: September 2015

Abstract
This paper shows the results of routine field application of an innovative tool for the integrated production optimization of surface facilities based on a biogenetic algorithm. Periodical runs of the tool have been performed in order to evaluate changes in configuration of the system or mitigation of possible production losses, allowing the complete exploitation of field potential at each stage of field production life.
The described integrated production optimization tool has the ability to integrate well performances, gathering system calculation, and process plant simulation in a unique environment in order to optimize the field configuration. Thanks to a powerful biogenetic algorithm the searching of the optimum field configuration is performed. Conflicts and interactions between variables, constraints, and operational limitations are balanced and solved holistically by the optimization tool. The operative procedure on the application of integrated modeling production optimization by means of this innovative tool, foresees the run of the model on a periodical basis in order to evaluate possible changes in asset configuration and mitigate production losses associated to workovers or system re-start after possible shutdown.
The integrated production modeling was developed for an on-shore oil field and applied regularly to evaluate different scenarios encountered during its operational life and optimize the field configuration at each stage. This paper illustrates different examples coming from the application of the operative procedure for integrated production optimization modeling. First, results are presented on the application of the tool to mitigate production losses during a workover. After a complete field shutdown, different scenarios were analyzed with the support of the optimization tool in order to evaluate the best configuration during the startup phase. Finally, the optimum desired flow rate was calculated for a gas-lift well in order to maximize the global system production. Results of the simulation were shared with the reservoir department for the management of gas injection rate.
Short-term production operation management is supported by routinely application of the presented innovative tool. The holistic optimization of complex surface systems allows the complete exploitation of field potential and production losses mitigation at each stage of field production life.
Improving Fiber-Optic System Reliability in Permanent Installations
Authors: Blount C. G. , Friehauf K. E. , Smith B. E. , Smith D. P. , Jaaskelainen Mikko , Baldwin C. S. 
Published: September 2015

Abstract
Permanent installation of fiber-optic (FO) sensors, whether discrete or distributed, provides beneficial monitoring of a wide variety of parameters during every stage of a well's useful life—from drilling and completions, through the productive period, up to and including permanent abandonment—assuming that the sensors do not fail during installation or subsequent wellbore intervention operations. Long-term reliability is critical to obtain maximum benefit of FO based sensor installations and is crucial to increased adoption of this technology in the oil and gas industry. FO system reliability depends on several factors and requires diligent attention to numerous details, a responsibility shared by manufacturers, service companies, and oil and gas operating companies.
Unexpected signal degradation of FO cables experienced in several instrumented wells required an engineered program approach to understand the failures and guide system improvement developments. Multiple-wavelength optical time domain reflectometer (OTDR) technology was used to diagnose symptoms of the fiber degradation. The importance and usefulness of OTDR technology was recognized, and a program to monitor fiber “health” with measurements recorded at regular intervals was developed to capture crucial historical records of the fiber/cable performance before system installation, during installation, and after installation. The historical progression of optical signal degradation proved to be invaluable in discerning root causes for this degradation. In the problematic FO cables, OTDR traces suggested various failure modes, including hydrogen darkening, fiber bending, and, in one well, a cable breach.
An enabler to frequent OTDR data collection is the ability to remotely operate the FO interrogation units and OTDR equipment. Travel to remote well locations is costly in terms of travel expenses and personnel. It interferes with accomplishing other tasks and often requires the assistance or presence of field operations personnel for onsite access. The system requirements and components used to remotely operate the onsite FO electronic interrogators in the monitoring program are described in this paper.
Based on the OTDR data, additional testing programs were initiated, new cables were designed and assembled, and quality assurance protocols were added. This paper describes the optical fiber “health” monitoring program, reviews case histories, emphasizes the importance of this diagnostic information, and summarizes developments to improve FO system reliability. Significantly improved reliability has been recognized in current installations and is expected to continue for future permanent installations based on the FO “health” program learnings.
OPEC and Unconventional Resources
Authors: Ashayeri Cyrus , Ershaghi Iraj 
Published: September 2015

Abstract
Crude oil and natural gas have been major pillars of the modern civilization during the past century. They are among the most valuable depletable global resources. The energy market has witnessed many oil price shocks during the past several decades. Such instabilities have impacted the global oil and gas industry in ways that have included disruption of investment in the infrastructure, slowdown of advancements in technology development, and backwardness on attracting and training creative solution providers. OPEC (Organization of Petroleum Exporting Countries) has been partly blamed for instigating such price instabilities. Recently, and since the latter part of 2014, in the fear that the shale resource developments may affect the market share of the OPEC producers, oil prices have dropped significantly because of OPEC countries, while suffering losses to their own economies, flooded the market with cheap oil. The global oil industry is now facing a similar situation it has faced several times during the last three decades.
Advantages and disadvantages of low oil prices for both net exporters and net importers of crude oil, as well as the global economy, have been extensively discussed in the literature. Based on the available statistics, while in the short terms, OPEC producers may regain their market shares by producing low cost conventional oil and discouraging shale oil and gas developments, in the long runs, this might not be a successful strategy. OPEC countries in few decades will be paying a high price when their conventional resources reach to levels barely satisfying their domestic needs. Furthermore, because of current orchestrated low prices for shale resources they are preventing their own countries from investing in the development of unconventional resources in terms of technology, manpower and pace of development. In this study we examine the potential of source rock development in some OPEC countries and discuss the importance of realizing the real value of crude oil when it gets to pricing a depletable resource and considering the substitution cost.
Development And Qualification Of A New High Pressure Gas Tight Rotary Shouldered Connection Incorporating Metal-to-Metal Technology For Deepwater Drilling And Completion Applications
Authors: Bassarath W. , LaFuente M. , Branly R. 
Published: September 2015

Abstract
Deepwater drilling and completions operations particularly in the Gulf of Mexico have a growing need for gas tight connections incorporating a metal-to-metal seal. This has been motivated by wells requiring drill stem testing, high-pressure completions/hydraulic fracturing jobs or managed pressure/under-balanced drilling operations. Safety and well integrity concerns further accentuate the need for a no compromise approach when developing connections with gas tight capability. In response to these industry needs a new gas tight connection with a metal-to-metal rotary seal has been developed. This premium high-pressure connection allows the same drillstring to be utilized for both drilling and completion operations, representing a considerable cost saving and improved efficiency over conventional industry practice.
This paper details the development and qualification of this new double-shoulder gas tight connection for drilling and other drillpipe based applications. Several concepts were assessed by Finite Element Analysis (FEA) and the final solution involved a hybridized version of a premium high torque connection and the connection from a drill-pipe-riser. The connection therefore provides the high pressure capability of premium casing or tubing connections coupled with the robustness and increased torsional strength associated with a double shoulder rotary connection. Qualification of the new product was performed on the most critical sizes and involved industry standard physical testing including make & break, overtorque, combined loading and fatigue testing. In fact, it provides one of the highest operating safety margins of any gas tight connection and is qualified to 30,000 psi internal pressure and 25,000 psi external pressure. Results of the full qualification are presented and discussed below.
CFD Modeling Of WBGT For An Offshore Platform
Authors: Tsai Kuochen 
Published: September 2015

Abstract
A wet-bulb globe temperature (WGBT) model has been incorporated into computational fluid dynamics (CFD) software to assess heat stress for the safety of workers on an offshore platform crowded with oil processing units. The model contains all critical elements needed to model WBGT, including conductive and convective heat transfer from the ambient air, radiative heat from the hot processing unit surfaces, solar load and ambient atmosphere, and the blockage of equipment, pipes and structural frames of the platform.
The CFD model was constructed with geometry files directly imported from 3-D modeling software used for large offshore platform structures. The imported geometry was then extracted for necessary parts critical for the thermal modeling. Smaller features, such as deadleg pipes, nuts and bolts that won't influence the results are removed to reduce computational costs. The parts were then grouped according to thermal boundary conditions to be applied, including temperature, heat transfer coefficients and emissivity. A wrapping mesh was applied to convert the CAD geometry into a meshable domain and mesh was generated with specified sizes that can eliminate small gaps and undesirable features ill-suited for CFD solutions. A WBGT model was incorporated into a commercial CFD software package using an iterative procedure from the work of LilJegren et al. (2008). The inclusion of the WBGT model greatly enhances the predictive capability of CFD models for assessing the heat stress experienced by human operators due to its ease of use without resorting to the modeling of human body surfaces and locations.
The model was carefully verified by comparing the CFD results with explicitly modeled WBGT sensor surfaces and the impact of radiation, wind speed and relative humidity are shown. The modeled results for the offshore platform show that it is necessary to insulate the processing units. The feasibility of such a comprehensive model greatly enhances the understanding of the heat stress distribution and provides new opportunities for remedial actions.
CFD Simulation of Turbulent Flow Structure in Stratified Gas/Liquid Flow and Validation with Experimental Data
Authors: Dabirian Ramin , Mansouri Amir , Mohan Ram , Shoham Ovadia , Kouba Gene 
Published: September 2015

Abstract
Although two-phase stratified flow pattern commonly occurs in petroleum industry the understanding of it, in terms of structure of the wave interface and the ensuing interaction between the two phases, is limited compared to single phase flow. Also, most of the studies have not taken the velocity profile across the pipe cross-section into account, rather just focused on the average velocity of each cross section. This paper will provide a unique insight into these velocity profiles, which are critical for frictional pressure drop calculations and prediction of phenomena such as wall effects of multiphase flow, erosion, corrosion, hydrate formation, wax deposition, etc. The objective of this paper is the analysis of this gas-liquid flow pattern in a horizontal pipe utilizing Computational Fluid Dynamics (CFD) simulation and comparison of the results with experimental data. The scope also includes the investigation of turbulent flow structure beneath gas-liquid interface by calculating the stream-wise velocity profile.
Experimental studies have been conducted to investigate gas-liquid stratified flow in horizontal pipe. A unique experimental facility was constructed with a 4-in ID PVC pipe and measurements were performed utilizing air-water. Liquid level at the center of the pipe is measured by ultrasonic proximity sensor at different superficial velocities of gas and liquid. Along with experimental tests, CFD simulations for the same test conditions have been performed using a commercial CFD code. For tracking the two-phase interface, Volume of Fluid (VOF) method was applied. The numerical simulation was obtained with the Realizable k-epsilon model of turbulence.
Comparing the CFD simulation results and liquid hold up measured experimentally revealed a good agreement (discrepancy&lt;±15%). The experimental data also show that at constant superficial liquid velocities, the liquid level increases with decreasing superficial gas velocities. The validation of the CFD results with experimental data indicates that, CFD simulation has the potential to be used for facility design and scale-up processes in petroleum industry.
Ensemble Model Predictive Control for Robust Automated Managed Pressure Drilling
Authors: Eaton Ammon N. , Beal Logan D. , Thorpe Sam D. , Janis Ethan H. , Hubbell Casey , Hedengren John D. , Nybø Roar , Aghito Manuel , Bjørkevoll Knut , Boubsi Rachid El , Braaksma Jelmer , van Og Geertjan 
Published: September 2015

Abstract
For automation of managed pressure drilling (MPD) to succeed, the automation system needs access to accurate measurement data and the ability to translate this into a correct representation of reality in the well. However, inaccuracies due to calibration problems and errors or omissions in manually entered data may combine with spurious behavior in the control model to make the automation system unreliable. This study presents a novel control scheme for automated MPD that addresses the problem of model reliability by using multiple control models to provide optimal control moves, even with the failure of one or two models.
This work simulates the ability to optimize MPD operations with realistic measurement signals using Model Predictive Control (MPC) with a range of model types. Further, it provides a robust automated MPD system to reduce interruptions to drilling operations. This work makes use of a high fidelity dynamic well bore model in addition to low order and empirical control models. The three controllers feed into a switch that selects the best available controller recommendation and allows for a seamless transition between controllers. The switch control scheme enables automated switching between the controllers in the event of one or two models failing and also allows for the tuning and troubleshooting of one model while the others continue to run, all without any interruption to the drilling process.
One of the key innovations in the ensemble switch is the seamless transition between controllers. This is accomplished by using the current process manipulated variable values as initial values for the optimization routines in the model predictive controllers that are not actively used to control the well. The strategy is tested in common drilling situations.
Two typical drilling scenarios are simulated: normal drilling operations and a pipe connection procedure. The validity of the novel control structure in each scenario is verified through simulated outliers, drift, and noise, as well as simulated controller failure and lack of optimal solution convergence. The controller is able to maintain bit pressure within +/− 1 bar of the 400 bar set point during normal drilling operations despite temporary signal loss and poor data quality. Also, the bit pressure is held within +/− 5 bar of the 340 bar set point during a pipe connection procedure with no bit pressure measurements available to the controller.
The techniques presented here can be used for more robust and stable automated MPD. Moreover, multiple models provide benefits that are typically associated with improved reliability due to hardware and safety systems redundancy allowing drilling to continue with fewer interruptions.
A Comprehensive Study of Proppant Transport in a Hydraulic Fracture
Authors: Blyton Christopher A. , Gala Deepen P. , Sharma Mukul M. 
Published: September 2015

Abstract
The effective placement of proppant in a fracture has a dominant effect on well productivity. Existing hydraulic fracture models simplify proppant transport calculations to varying degrees and are often found to over-predict propped or effective fracture lengths by 100 to 300%. A common assumption is that the average proppant velocity due to flow is equal to the average carrier fluid velocity, while the settling velocity calculation uses Stokes' law. To accurately determine the placement of proppant in a fracture, it is necessary to rigorously account for many effects not included in the above assumptions.
In this study, the motion of particles flowing with a fluid between fracture walls has been simulated using a coupled CFD-DEM code that utilizes both particle dynamics and computational fluid dynamics calculations to rigorously account for both. These simulations determine individual particle trajectories as particle to particle and particle to wall collisions occur and include the effect of fluid flow and gravity. The results show that the proppant concentration and the ratio of proppant diameter to fracture width govern the relative velocity of proppant and fluid. Further, the dependencies of settling velocity on apparent fluid viscosity, proppant diameter and the density difference between the proppant and fluid predicted by Stokes' law were found to apply. However, additional effects have been quantified and shown to substantially alter the predictions from Stokes' law. Proppant concentration and slot flow Reynold's number were both shown to modify the settling velocity predicted by Stokes' law, as does the ratio of proppant diameter to slot width. The effect of leak-off was found to be negligible in terms of altering either the settling velocity or the relative velocity of proppant and fluid. The models developed from the direct numerical simulations have been incorporated into an existing fully 3-D hydraulic fracturing simulator. This simulator couples fracture geomechanics with fluid flow and proppant transport considerations to enable the fracture geometry and proppant distribution to be determined. Unlike all previous studies, these effects are included together and so are shown to be inter-dependent, allowing us for the first time to accurately model proppant transport.
As noted above, proppant velocities have been accurately determined without simplifying approximations and with all relevant effects included, showing inter-dependence between the different effects. Two engineering fracture design parameters, injection rate and fluid rheology, have been varied to show the effect on proppant placement in a typical shale reservoir. This allows for an understanding of the relative importance of each and optimization of the treatment to a particular application.