bluuebunny/crossref_metadata_2025_split huggingface dataset:
Toward Drilling Automation: On the Necessity of Using Sensors That Relate to Physical Models
Authors: Cayeux E.. , Daireaux B.. , Dvergsnes E.W.. W. , Florence F.. 
Published: June 2014

Summary
Current topside and downhole instrumentation at the wellsite has been developed to manually conduct drilling operations. The emergence of automatic drilling-analysis software shows the limitations of today's measurement capabilities. It is therefore time to analyze the requirements for on-site instrumentation to implement new, efficient drilling-automation technologies.
On one hand, drilling is facing more and more difficult conditions with narrow geopressure windows, deepwater, or high-pressure/high-temperature (HP/HT) conditions. On the other hand, unconventional hydrocarbon reserves may require a considerable amount of wells to be profitable. Drilling automation, by means of smart safeguards, automatic safety triggers, managed-pressure drilling (MPD), and ultimately complete or semiautonomous drilling rigs, can provide the solution to safely construct wells in these challenging settings.
The common denominator for the vast majority of drilling-automation solutions is the use of physical models of the drilling process in the form of heat-transfer, mechanical, and hydraulic models. By analyzing the requirements of those models for necessary boundary conditions, it is possible to derive which measurements should be made both at surface and downhole to obtain stable and accurate calculations. This analysis also provides a way to estimate the necessary accuracy of the boundary conditions to ensure reaching the target control tolerance.
By use of the boundary-condition analysis, it is possible to derive precisely which measurements should be performed and where they should be performed. As a result, a typical organization of sensors that is compatible with the implementation of drilling-automation solutions is derived.
Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater Extended-Reach Well
Authors: Gradishar John , Ugueto Gustavo , van Oort Eric 
Published: June 2014

Summary
This paper details the case history of the highly challenging extended-reach deepwater A-10 well, drilled in the Ursa (“Bear” in Latin) prospect in the Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) at a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole (OH), two subsequent sidetracks, and two mechanical bypasses, a number of significant hole problems materialized that caused extensive nonproductive time (NPT) and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high-deviation and extended-reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the GOM's challenging geopressured environment. In all, at least five independent borehole-failure mechanisms were encountered while drilling the OH and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor:
Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10OH Lost circulation in induced fractures, with associated heavy mud losses Borehole fatigue, caused by stress cycling on weak formations caused by annular-pressure fluctuations Borehole instability caused by too-low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 Sidetrack 1 Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 Sidetrack 1 Bypasses 1 and 2, and ultimately forced the well to be completed in shallower Magenta sands Complicating factor: barite sag of synthetic-based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms
An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices [e.g., for hole cleaning, equivalent-circulating-density (ECD) management, sag control], and to the development of new systems (including novel, sag-resistant synthetic-based-mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here to help the future drilling of extended-reach wells in geopressured, low-margin deepwater environments.
A Generalized Framework Model for the Simulation of Gas Production in Unconventional Gas Reservoirs
Authors: Wu Yu-Shu , Li Jianfang , Ding Didier-Yu , Wang Cong , Di Yuan 
Published: June 2014

Summary
Unconventional gas resources from tight-sand and shale gas reservoirs have received great attention in the past decade around the world because of their large reserves and technical advances in developing these resources. As a result of improved horizontal-drilling and hydraulic-fracturing technologies, progress is being made toward commercial gas production from such reservoirs, as demonstrated in the US. However, understandings and technologies needed for the effective development of unconventional reservoirs are far behind the industry needs (e.g., gas-recovery rates from those unconventional resources remain very low). There are some efforts in the literature on how to model gas flow in shale gas reservoirs by use of various approaches—from modified commercial simulators to simplified analytical solutions—leading to limited success. Compared with conventional reservoirs, gas flow in ultralow-permeability unconventional reservoirs is subject to more nonlinear, coupled processes, including nonlinear adsorption/desorption, non-Darcy flow (at both high flow rate and low flow rate), strong rock/fluid interaction, and rock deformation within nanopores or microfractures, coexisting with complex flow geometry and multiscaled heterogeneity. Therefore, quantifying flow in unconventional gas reservoirs has been a significant challenge, and the traditional representative-elementary-volume- (REV) based Darcy's law, for example, may not be generally applicable.
In this paper, we discuss a generalized mathematical framework model and numerical approach for unconventional-gas-reservoir simulation. We present a unified framework model able to incorporate known mechanisms and processes for two-phase gas flow and transport in shale gas or tight gas formations. The model and numerical scheme are based on generalized flow models with unstructured grids. We discuss the numerical implementation of the mathematical model and show results of our model-verification effort. Specifically, we discuss a multidomain, multicontinuum concept for handling multiscaled heterogeneity and fractures [i.e., the use of hybrid modeling approaches to describe different types and scales of fractures or heterogeneous pores—from the explicit modeling of hydraulic fractures and the fracture network in stimulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix]. We demonstrate model application to quantify hydraulic fractures and transient flow behavior in shale gas reservoirs.
Optimization Algorithms Based on Combining FD Approximations and Stochastic Gradients Compared With Methods Based Only on a Stochastic Gradient
Authors: Yan Xia , Reynolds Albert C. 
Published: June 2014

Summary
Optimization algorithms that incorporate a stochastic gradient [such as simultaneous-perturbation stochastic approximation (SPSA), simplex, and EnOpt] are easy to implement in conjunction with any reservoir simulator. However, for realistic problems, a stochastic gradient provides only a rough approximation of the true gradient, and, in particular, the angle between a stochastic gradient and the associated true gradient is typically far from zero even though a properly computed stochastic gradient usually represents an uphill direction.
This paper develops a more robust optimization procedure by replacing the components of largest magnitude of the stochastic gradient with a finite-difference (FD) approximation of the pertinent partial derivatives. In essence, the objective of the method is to determine which components of the unknown true gradient are most important and then replace the corresponding components of the stochastic gradient with more-accurate FD approximations. This modified gradient can then be used in a gradient-based optimization algorithm to find the minimum or maximum of a given cost function. Our focus application is the estimation of optimal well controls, but it is clear that the method could also be used for other applications, including history matching.
A Semi-Implicit Approach for Integrated Reservoir and Surface-Network Simulation
Authors: Liang Jialing , Rubin Barry 
Published: June 2014

SummaryConventionally, methods of coupling reservoirs and surface networks are categorized into implicit and explicit approaches. The term "implicit coupling" indicates that the two simulators solve unknowns together, simultaneously, or iteratively, whereas "explicit coupling" indicates that the two simulators solve unknowns sequentially and exchange their boundary conditions at the last coupled time tn.The explicit approach is straightforward to implement in existing reservoir and surface-network models and is widely used. Explicit coupling does have drawbacks, however, because well rate and pressure oscillations are often observed.In this paper, a new semi-implicit method for coupled simulation is presented. This technique stabilizes and improves the accuracy of the coupled model. The "semi-implicit coupling" overcomes the problems found in explicit-coupling methods without requiring the complexity of a fully implicit coupled model.The new approach predicts inflow-performance-relationship (IPR) curves at the next coupled time tn+1 by simultaneously conducting well tests for all wells in the reservoir before actually taking the required timestep. All wells first flow simultaneously to the next coupled time tn+1 with the well rates unchanged from the last coupled timestep. The timestep is rewound, and all well rates are reduced by a uniform fraction and then simultaneously flow again to tn+1. By extrapolating the resulting well pressures, the well's shut-in pressures at time tn+1 are determined, and thus, straight-line IPRs are produced. The new IPR curves approximate better each well's drainage region at tn+1 and each well's shut-in pressure at tn+1 which helps to stabilize the explicitly coupled model.The new coupling technique normally does not require iteration between the reservoir and surface network and normally has the stability and accuracy characteristics of an implicitly coupled approach. Because the well tests already account for individual well-drainage regions, an explicit knowledge of the well-drainage region is not required. Because of the stabilized IPR, the approach also was found to reduce the overall computational time compared with explicit coupling.Applications of the new approach are presented that show significant improvements surpassing explicit coupling in both stability and accuracy.
Reduced-Order Modeling for Compositional Simulation by Use of Trajectory Piecewise Linearization
Authors: He Jincong , Durlofsky Louis J. 
Published: June 2014

Summary
Compositional simulation can be very demanding computationally as a result of the potentially large number of system unknowns and the intrinsic nonlinearity of typical problems. In this work, we develop a reduced-order modeling procedure for compositional simulation. The technique combines trajectory piecewise linearization (TPWL) and proper orthogonal decomposition (POD) to provide a highly efficient surrogate model. The compositional POD-TPWL method expresses new solutions in terms of linearizations around states generated (and saved) during previously simulated “training” runs. High-dimensional states are projected (optimally) into a low-dimensional subspace by use of POD. The compositional POD-TPWL model is based on a molar formulation that uses pressure and overall component mole fractions as the primary unknowns. Several new POD-TPWL treatments, including the use of a Petrov-Galerkin projection to reduce the number of equations (rather than the Galerkin projection, which was applied previously), and a new procedure for determining which saved state to use for linearization are incorporated into the method. Results are presented for heterogeneous 3D reservoir models containing oil and gas phases with up to six hydrocarbon components. Reasonably close agreement between full-order reference solutions and compositional POD-TPWL simulations is demonstrated for the cases considered. Construction of the POD-TPWL model requires preprocessing overhead computations equivalent to approximately three or four full-order runs. Runtime speedups by use of POD-TPWL are, however, very significant—up to a factor of 800 for the cases considered. The POD-TPWL model is thus well suited for use in computational optimization, in which many simulations must be performed, and we present an example demonstrating its application for such a problem.
Unstructured Cut-Cell Grids for Modeling Complex Reservoirs
Authors: Mallison Brad , Sword Charles , Viard Thomas , Milliken William , Cheng Amy 
Published: June 2014

SummaryEffective workflows for translating Earth models into simulation models require grids that preserve geologic accuracy, offer flexible resolution control, integrate tightly with upscaling, and can be generated easily. Corner-point grids and pillar-based unstructured grids fail to satisfy these objectives; hence, a truly 3D unstructured approach is required. This paper describes unstructured cut-cell gridding tools that address these needs and improve the integration of our overall reservoir-modeling workflows.The construction of simulation grids begins with the geologic model: a numerical representation of the reservoir structure, stratigraphy, and properties. Our gridding uses a geochronological (GeoChron) map from physical coordinates to an unfaulted and unfolded depositional coordinate system. The mapping is represented implicitly on a tetrahedral mesh that conforms to faults, and it facilitates accurate geostatistical modeling of static depositional properties. In the simplest use case, we create an explicit representation of the geologic model as an unstructured polyhedral grid. Away from faults and other discontinuities, the cells are hexahedral, highly orthogonal, and arranged in a structured manner. Geometric cutting operations create general polyhedra adjacent to faults and explicit contact polygons across faults. The conversion of implicit models to explicit grids is conceptually straightforward, but the implementation is nontrivial because of the limitations of finite precision arithmetic and the need to remove small cells formed in the cutting process.In practice, simulation grids are often constructed at coarser resolutions than Earth models. Our implementation of local grid coarsening and refinement exploits the flexibility of unstructured grids to minimize upscaling errors and to preserve critical geologic features. Because the simulation grid and the geologic model are constructed by use of the same mapping, fine cells can be nested exactly inside coarse cells. Therefore, flow-based upscaling can be applied efficiently without resampling onto temporary local grids.This paper describes algorithms and data structures for constructing, storing, and simulating cut-cell grids. Examples illustrate the accurate modeling of normal faults, y-faults, overturned layers, and complex stratigraphy. Flow results, including a field-sector model, show the suitability of cut-cell grids for simulation.
Unconstrained Voronoi Grids for Densely Spaced Complex Wells in Full-Field Reservoir Simulation
Authors: Fung L.S.K.. S.K. , Ding X.Y.. Y. , Dogru A.H.. H. 
Published: June 2014

Summary
Accurate representation of near-well flow is an important subject matter in reservoir simulation. In today's field-scale reservoir simulation, cell-centered structured grids remain the predominant practice. Typically, well-inflow performance of the perforated cells is connected to the finite-volume solution by means of well indices that may not be well-defined when the wellbore intersects the finite-volume cells in a complex trajectory. Fine gridding is also required to resolve the flow dynamics in the near-well regions. Strong grid-orientation sensitivities can also contribute to the numerical errors and may require significant local grid refinement to alleviate. There are ongoing resesarch-and-development (R&D) efforts on applying unstructured grids to better represent the near-well flow in reservoir simulation, but their applications are mainly in single-well study or sector modeling with a few wells. Some of the reasons cited for this include (1) the lack of an effective, easy-to-use full-field complex well-gridding tool; (2) the lack of supporting unstructured workflow for full-cycle reservoir simulation; (3) the cost of unstructured-grid simulation; and (4) the availability of post-analysis and visualization tools for unstructured-grid simulation.
The paper describes a novel method to automatically generate unstructured grids that conform to complex well paths in field-scale simulation. The method uses a multilevel approach to place cells optimally within the solution domain on the basis of the “regions of interests.” The wellbore geometry is honored by means of the construction of a near-well grid that is complemented with multilevel quad-tree (Fig. 1) refinements to achieve the desired resolution in grid transition zones. The method includes an algorithm to remove small cells and pinching cells on the basis of local grid quality measures and cell prioritization to honor well paths. The gridding process forms a component of a production-level reservoir-simulation workflow. The use of unstructured grid results in computational savings by placing cells where the resolution is needed. An in-house massively parallel simulator is used to run the unstructured-grid models. Simulation examples for full-field applications with hundreds of complex wells by use of both structured grids and unstructured grids will be used to compare results, accuracy, and performance of the gridding method for reservoir simulation.
Development of an Analytical Injectivity Model for Non-Newtonian Polymer Solutions
Authors: Li Zhitao , Delshad Mojdeh 
Published: June 2014

Summary
In applications of polymer flood for enhanced oil recovery (EOR), polymer injectivity is of great concern because project economics is sensitive to injection rates. In-situ non-Newtonian polymer rheology is the most crucial factor that affects polymer injectivity. There are several ongoing polymer-injection field tests in which the field injectivities differ significantly from the simulation forecasts. We have developed an analytical model to more accurately calculate and predict polymer injectivity during the field projects to help with optimum injection strategies.
Significant viscosity variations during polymer flood occur in the vicinities of wellbores where velocities are high. As the size of a wellblock increases, velocity smears, and thus polymer injectivity is erroneously calculated. In the University of Texas Chemical Flooding Simulator (UTCHEM), the solution was to use an effective radius to capture the “grid effect,” which is empirical and impractical for large-scale field simulations with several hundred wells. Another approach is to use local grid refinement near wells, but this adds to the computational cost and limits the size of the problem. An attractive alternative to previous approaches is to extend the Peaceman well model (Peaceman 1983) to non-Newtonian polymer solutions.
The polymer rheological model and its implementation in UTCHEM were validated by simulating single-phase polymer injectivity in coreflood experiments. On the basis of the Peaceman well model and UTCHEM polymer rheological models covering both shear-thinning and shear-thickening polymers, an analytical polymer-injectivity model was developed. The analytical model was validated by comparing results of different gridblock sizes and radial numerical simulation. We also tested a field case by comparing results of a fine-grid simulation and its upscaled coarse-grid model. A pilot-scale polymer flood was simulated to demonstrate the capability of the proposed analytical model. The model successfully captured polymer injectivity in all these cases with no need to introduce empirical parameters.
Control and Development of Simultaneous-Operations Drilling, Workover, and Well Services: Successful Case in La Hocha Field
Authors: Castañó Ricardo , Diaz Oscar , Cruz Ediberto , Ortiz Everardo , Rueda Henry , Herrera Andrea , Aldana Erwin , Gutierrez Wilian 
Published: June 2014

Abstract
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The operator company, committed to its performance in industrial safety, occupational health, the reduc tion of its environmental impacts and the protection of its ass ets, towards the year 2004, it de veloped its concurrent operation guidelines for places where two or more high-risk operations are carried out, which include drilling, completion, work-over, well-service activities, well production, and civil, mechanical and electrical works of facilities. This is so lely done to ide ntify all hazard s, evaluate and control all risk-taking in these activities to avoid the o ccurrence of incidents involving people, the environment and damage to company equipment.
It was necessary to conduct several activities at its production field, LA HOCHA 1 location, to apply our concurrent operation guidelines on that platform as a res ult of a production increase and the development of new projects.
The activities conducted on the same location, La Hocha 1, were:LH 9 well intervention using Flush By equipmentLH 7 well workover ServiceLH 1-LH 7-LH 8 LH 9 ProductionLa Hocha 25 DrillingCPF Construction.
Two purposes were defined on La Hocha concurrent operation plan; the first is handling, authority relations and responsibility in matters concerning HSE, and the second is to establish procedures and guidelines which must be implemented when various activities are conducted simultaneously including drilling or produc tion operations on a platform or a worksite which for this specific case was La Hocha 1.
After carrying out these concurrent activities, we were abl e to fulfill our propos ed goal of zero injuries to pe ople, no e nvironmental impact, no equipment damage, the fulfillment of all the plans prepared for each operation, and most of all recogni tion for the company for its excellent coordination and communication work performed during concurrent operations on La Hocha 1 Platform.
China Offshore HSE Management for Securing Platform Drilling Operations
Authors: Cheng Kun , Gokdemir Oktay M. , Cheng Zhong , Cetkovic Ivan , Li Yongjun , Li Shiguang 
Published: June 2014

Abstract
After experiencing severe weather events on offshore platforms in the Bohai Sea, China National Offshore Oil Corporation (CNOOC) adopted a health, safety, and environment (HSE) management initiative specifically for offshore platforms in that region. The event prevention and treatment measures adopted by CNOOC incorporate advanced management experience and hazard management technology with methods and characteristics unique to CNOOC. The HSE program controls risks of health, safety and environment risks during the process of drilling operations on offshore platforms, and treats mechanisms and causes of the operational risks equally with the detrimental accidents. To reduce risks and aid prevention, CNOOC’s HSE initiative is continuously enriched through by implementing precautionary measures.
This paper detail features of CNOOC’s HSE initiative, including accident prevention and treatment, risk reduction, and management control. The HSE platform adopts the management concept that accidents are preventable through full participation, different-leveled responsibility, programmed enforcement, and standardized scientific management method.