bluuebunny/crossref_metadata_2025_split huggingface dataset:
Artificial Neural Network Drilling Parameter Optimization System Improves ROP by Predicting/Managing Bit Wear
Authors: Gidh Yashodhan , Purwanto Arifin , Bits Smith 
Published: June 2014

Abstract
Tool manufacturers have made significant progress improving downhole drilling technologies, but little effort has focused on optimizing the drilling process. The set-it-and-forget-it approach and inherent inefficiencies of the automatic driller are inadequate for keeping bit parameters matched to lithology and wellbore conditions. The industry requires a new methodology to help rig-site personnel make informed drilling parameter decisions based on real-time offset data analysis that increases operating efficiency to reduce drilling costs.
To solve the problem an artificial neural network (ANN) drilling parameter optimization system was developed to provide rig-site personnel real-time information to ensure maximum run length from all bits and downhole tools at the highest possible ROP. Benefits of the new system include extended tool life, fewer trips and the ability to manage the bits dull condition.
The objective is to replace the human factor of applying operating parameters such as WOB and RPM with the intelligent ANN learned experience. Using the ANN software system, operating parameters can be selected based on the documented physical rock characteristics (offset log data) of formations being penetrated and then fine tuned for the bits specific cutting structure and wear rate. By following the real-time ANN recommendations, changes can be implemented to increase overall ROP while maximizing bit life by managing the dull condition.
The overall project results were positive and proved successful in all the trails carried out after this field trial. This paper will address the methodology of the new approach and highlight the importance of planning and implementing the drilling parameters in realtime.
Hydraulic Fracture Production Optimization With a Pseudo-3D Model in Multi-layered Lithology
Authors: Yang Mei 
Published: June 2014

Abstract
Systematic design and optimization procedures for hydraulic fracturing are available using two-dimensional (2D) (with constant fracture height) and pseudo three dimensional (p-3D) models to maximize well production by optimizing fracture geometry, including fracture height, half-length and width.
A multi-layered p-3D approach to design is proposed integrating Unified Fracture Design (UFD), fracture propagation models and Linear Elastic Fracture Mechanics (LEFM) relationship to generate optimized fracture geometry, including fracture height, width and half-length to achieve the maximized production. Containment layers are discretized to allow for plausible fracture heights when seeking convergence of fracture height and net pressure.
UFD sizes the fracture geometry to physically optimize the hydraulically fractured well performance. The Proppant Number is a correlating parameter, which in turn provides the maximum dimensionless productivity index (JD) corresponding to the optimum dimensionless fracture conductivity, CjD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set. However, UFD in its original form needs fracture height as an input parameter.
PKN or KGD fracture propagation models predict hydraulic fracture geometry and the associated net pressure. Linear Elastic Fracture Mechanics (LEFM) relationship calculates fracture height by finding the net pressure distribution at layers, which plays an important role when the fracture is propagating in the reservoir. In multi-layered reservoirs, the net pressure of each layer varies as a result of different rock properties. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the final equilibrium height defined by the condition where the fracture toughness equals the calculated stress intensity factor based on LEFM. After an equilibrium height and the corresponding net pressure at the center of perforation are obtained, PKN/KGD models are used again, to calculate fracture width and half-length at each layer. This work also allows for a calculation of the fracture height that would not propagate into unintended layers (i.e. gas cap and/or aquifer)
Expanding the Hydraulic Fracturing Options on Reservoirs with Water Zones in Western Siberia
Authors: Mendez Alfredo , Mazhirin Yury , Astafyev Vladimir , Alekseev Boris , Bortey Pavel 
Published: June 2014

Abstract
Hydraulic Fracturing in Western Siberia, Russia is a common practice that the need of stimulating wells in mature oil fields cannot be limited to non-complicated reservoirs. Wells requiring hydraulic fracturing with water zones either above or below is what we mean as reservoirs that require techniques that are out of the ordinary and day to day operations. A technique using dry solid material to contain the hydraulic fracture job within the zone of interest has been used in several wells and will be presented in this paper. The oil field Nivagalskoe which is located in Nizhnevartovsk area, Western Siberia, Russia is considered a mature oil field where due to the low value of the reservoir permeability, hydraulic fracturing these reservoirs require more than a skin bypass frac. Achieving a lengthier propped frac and descent net pressure increase is always a challenge on any hydraulic fracturing job execution but is always a must for the oil fields in the Nizhnevartovsk area. The challenge becomes when there are water zones close to the zone of interest to be stimulated via hydraulic fracturing. The objective is only not to design a job that will be limited in height by optimizing parameters commonly used in limiting frac geometry but to guarantee at best that the frac will not grow into the water zone. Several cas histories will be presented where all cases the water cut was measured before and after the hydraulic fracturing job. The technique used and recommendations will be presented to optimize future jobs. All other options to limit frac geometry considered will also be presented.
Cost-Effective Acid Stimulation of Carbonates Using Seawater-Based Systems Without Calcium Sulfate Precipitation
Authors: Berry S. L. , Boles J. L. , Smith K. L. 
Published: June 2014

Abstract
Water is a key element in oil and gas operations. Many operations need and/or are performed most ideally with fresh water, but its availability is decreasing in some locations around the world. One area of particular concern is offshore operations to stimulate carbonate formations.
Acid stimulation fluids are usually mixed with fresh water, but if fresh water supplies are limited or unavailable, seawater is sometimes substituted in part or full. However, when acid systems are mixed with seawater containing high levels of sulfate ions, calcium sulfate precipitates as the acid reacts with limestone or dolomite formation. The extent of calcium sulfate deposition or scaling, although sometimes accepted or ignored by some customers, can result in post-stimulation results far below their true potential.
Various technologies can remove sulfate from seawater; however, these technologies are expensive and logistically challenging or impractical to use on offshore installations or conventional stimulation vessels. Instead, a newly developed acidizing fluid system provides a cost-effective method to chemically inhibit calcium sulfate precipitation from sulfate-laden seawater during acid reaction, resulting in more effective stimulation of carbonate rock. This fluid system eliminates the need to pre-treat seawater, greatly simplifying logistics while maximizing stimulation efficiency.
This paper will demonstrate that calcium sulfate does precipitate from conventional acidizing fluid systems mixed with seawaters containing high levels of sulfate. It will further show that this precipitation decreases the solubility/stimulation of carbonate rock. Finally, this project will introduce and show the efficiency of a chemical method to treat seawater-mixed acid systems to effectively minimize or prevent the precipitation of calcium sulfate solids during carbonate acid stimulation treatments.
Sustaining a Dynamic Revolution: How BP Is Growing the Value Delivered From Transient Flow Modelling and Control
Authors: Calvert Patrick , Griffiths Peter 
Published: June 2014

Abstract
Steady state flow modelling has become common practice across the industry. Over the past decade, continued developments in the underlying modelling software have led to a greater up-take in steady state modelling as clear solutions emerge for a wide range of operational problems.
Whilst steady-state modelling has reached a level of maturity, dynamic modelling is less established as an operational support tool. This contrasts with an ever growing list of dynamic operability issues that have emerged from operating more challenging fields. Although firmly established in the flow assurance community, transient flow modelling has yet to achieve the same critical mass with the petroleum engineering community. The additional technical complexity of dynamic modelling means that it is more likely to be used in bespoke design studies than in the support of daily operations.
Within this paper, the challenges of developing a sustainable dynamic modelling capability will be discussed in reference to three phases: demonstrating value; crystallising interest and building regional capability. For each phase, supporting evidence will be given from a variety of projects including slug control, well start-up and well deliquification.
Dynamic modelling is beginning to play a significant role in BP's operations. The significance of dynamic modelling and control in delivering safe, stable and optimal performance is now well understood across the company. The remaining challenge is to crystallise recent success into a fully sustainable dynamic modelling capability.
New HT/HP Technology for Geothermal Application Significantly Increases On-Bottom Drilling Hours
Authors: Orazzini Simone , Kasirin Regillio , Ferrari Giampaolo , Bertini Alessandro , Bizzocchi Isabella , Ford Robert , Li Qingxiu , Zhang Ming 
Published: June 2014

Abstract
Geothermal energy has been use for centuries to satisfy general heating requirements. The modern geothermal plant is powered by production wells drilled to a source rock to produce steam at the surface. Depending on the location and depth, source formation temperatures vary.
In Italy, the operator must penetrate very hard and abrasive sediment and metamorphic formations to access steam in the granite basement formation. Historically, this was accomplished with a tungsten carbide insert (TCI) roller cone bit (RC). Standard geothermal bits and components, including grease and elastomer seals, are adequate for temperatures up to 150°C (302°F). Beyond these temperatures, the bit’s internal components and lubricating material can degrade causing bearing failure limiting on-bottom drilling hours. In the application, the bottom hole temperature is approximately 180°C (350°F) and in some instances it can exceed 280°C (536°F). The extreme heat reduces on-bottom drilling hours leading to multiple bit runs/trips that drive up development costs. The operator required new roller cone technology that would endure the downhole environment.
To solve this challenge, a series of tests were conducted with temperature resistant elastomers and grease compounds in a controlled laboratory environment. The experiments resulted in a new line of roller cone bits equipped with an innovative bearing system that includes new proprietary composite elastomer seals with Kevlar® fabric and a proprietary high temperature grease formula. These innovations increased seal life, lubricity and load capacity at elevated temperatures for HT/HP applications.
The new geothermal bit technology has been run in the Italian application with outstanding results. Compared to standard roller cone products, the high-temperature bits have greatly increased on-bottom drilling hours while reducing total bit consumption and costly tripping for bit change out. Since successful development of the geothermal project is tied to reducing drilling costs, the new bit technology has significantly improved project economics. The authors will discuss development of the high temperature seal and grease compounds for drilling the granite basement source rock. They will also outline changes to the TCI cutting structure, field application, dull grades and bit performance data.
The Future of Surveillance—A Survey of Proven Business Practices for Use in Oil and Gas
Authors: Lochmann Mark 
Published: June 2014

Summary
Surveillance in one form or another has been used in oil and gas production almost since the industry began. The initial goal was relatively simple and straightforward: monitoring output against production targets for individual wells and troubleshooting those same wells when problems occurred. The actual scope of what could be accomplished was limited by available resources and lack of tools and technology, so only a very few high-value wells could be monitored closely.
With modern complex oil- and gas-production operations, the goal of surveillance has evolved from ensuring a single well's performance to managing a producing asset against its potential—a much loftier endeavor that must consider each of the system components, the interaction of those components, and the impact of factors external to the system. Traditional approaches to surveillance are no longer adequate to meet the current and continuously emerging and increasingly complex requirements of oil and gas operations. Modern and next-generation surveillance systems must deliver more.
More recently, in both mature fields and greenfields, the industry has seen increased implementation of more-sophisticated solutions with richer capabilities (e.g., monitoring centers that feed data into real-time displays; the enabling of operations staff to see the status of all key measurements; and model-based, integrated workflows to automate and facilitate operational excellence). The addition of advanced analytics, expert systems, and process automation (all of which routinely leverage real-time information) has taken surveillance from gathering production data on grease books to sophisticated solutions that combine business or operational intelligence with automated technical calculations. Indeed, these are the types of surveillance solutions expected by forwardthinking managers. However, despite these successes, widespread uptake of these types of solutions is slow, as is often the case in our industry.
This paper provides a survey of business practices proven in other complex industries, including management by exception (MBE), business intelligence (BI), situational awareness (SA), model-based decision support (MBDS), advanced process control (APC), and consequential analysis (CA). With learning from use in other industries, these business practices, enabled by state-of-the art information technology, can be combined and implemented to build next-generation surveillance solutions that will allow oil and gas producers to manage production assets against their potential in a safe, environmentally responsible way and in support of corporate goals.
Closed-loop Feedback Control for Production Optimization of Intelligent Wells under Uncertainty
Authors: Dilib F. A. , Jackson M. D. 
Published: June 2014

Abstract
Significant challenges remain in the development of optimized control techniques for intelligent wells, particularly with respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model or ensemble of models used in the optimization capture all possible reservoir behaviors at the individual well and completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We suggest that closed-loop feedback control strategies, triggered by monitoring at the surface or downhole, can increase NPV and mitigate reservoir uncertainty. We do not neglect reservoir model predictions entirely; rather, we use a model-based approach to optimize adjustable parameters in the feedback control strategies. We assess the implementation of an intelligent horizontal well in a thin oil reservoir in the presence of reservoir uncertainty, and evaluate the benefit of using different inflow control actuators in conjunction with surface and/or downhole monitoring equipment.
Four inflow control strategies are tested. The first is an open-loop approach, using a fixed control device to balance inflow along the well, sized prior to installation. The second and third are closed-loop feedback control strategies, employing intelligent completions that can be controlled from the surface. The second strategy uses on/off inflow control devices, operated according to surface flow rates and phase measurements obtained during zonal well tests. The third strategy uses variable control devices, operated according to downhole multiphase flow meters. The fourth strategy employs a gradient-based optimization algorithm to find the dynamic optimal inflow control behavior. This strategy assumes perfect reservoir knowledge and is implemented only for benchmarking of the feedback control strategies.
Our result suggests that closed-loop control based on direct feedback between reservoir monitoring and inflow valve settings can yield close-to-optimal gains in NPV compared to uncontrolled production, even if the reservoir does not behave as predicted. Open-loop control yields significantly lower gains in NPV and is also a riskier strategy, because unpredicted reservoir behavior can lead to negative returns. Closed-loop feedback control can mitigate uncertain reservoir behavior, even when this lies outside the range of model predictions; moreover, the uncertainties which have the most significant impact on production may not be the most difficult to mitigate.
Simulation of Gel Filter Cake Formation, Gel Cleanup, and Post-Frac Well Performance in Hydraulically Fractured Gas Wells
Authors: Charoenwongsa S. , Kazemi H. , Fakcharoenphol P. , Miskimins J. L. 
Published: June 2014

Abstract
Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses this issue by using a gas-water flow model which simulates fracture propagation with gel filter cake formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In this model, the gel filter cake thickness is calculated based on experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on the matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
Statistical Analysis of Significant Factors Affecting Perforation Flow at Well Scale
Authors: Li Baoyan , Sun Datong , Satti Rajani 
Published: June 2014

Abstract
Well perforation rebuilds the communication between the wellbore of a cased well and the formation to produce gas/oil. Completion and reservoir engineers expect to maximize well production by the optimal design of well perforation. However, are perforation parameters the significant factors influencing the productivity of a perforated well? Will drilling and perforation damages, combined with perforation factors, significantly affect the production performance of the well? To address these technical concerns, we need to perform a sensitivity analysis to screen and rank the significant factors affecting the productivity of a perforated well.
The one-factor-a-time methodology has been used to perform a sensitivity analysis of the perforation flow. This methodology is simple, but the interactions between the factors are not considered and no ranking of significant factors is provided. To overcome these disadvantages we introduce the methodologies of experimental design and analysis to screen and rank the significant factors affecting the perforation flow at well scale.
In this study, a two-level factorial design is used to collect simulation results of perforation flow at well scale from the commercial computational fluid dynamics (CFD) software ANSYS FLUENT. Analysis of variance (ANOVA) method and regression analysis method are used to analyze and rank the significant factors affecting the perforation flow at well scale.From this sensitivity analysis study, we conclude:
The depth of penetration (DOP) is the most significant factor to the productivity and skin factor of the vertical well, if the shot density is six shots per foot and shot phasing is 60 degrees. The interactions between any two of the following factors: penetration depth, return permeability of the drilling-damage zone, and return permeability of the perforation crushed zone are significant to the skin factor of the vertical well. Permeability anisotropy is a significant factor to the productivity of a perforated vertical well. The radius of the perforation tunnel is not a significant factor influencing the skin factor of a well, and neither are the thicknesses of the drilling-damage zone and crushed zone of perforation.
Accelerating Regional Transformation Using a Centralised Business Process Repository
Authors: Newman Mark , Feineman David R 
Published: June 2014

Abstract
In a globally distributed oil and gas organization, transformation of business processes, adoption of digital oilfield technology and developing competencies of staff presents a significant challenge. Variations in culture, working practices, partial definitions of what constitutes ‘best practice’, and achieving sustainable change and creating an environment for continued change presents a complex picture for transformation delivery.
The Morphix Company and BP's Field of the Future Flagship have been working together for the past 7 years to adopt methods for business transformation based on a centralised repository of reference models. These are being used to support specific transformation projects in the areas of base management, well planning and construction, and other functions making use of digital oilfield technology.
The iterative development of centralised reference models, their management, and implementation will be discussed, specifically addressing how best practice is being captured, how reference models are evolved, how reference models are used in specific transformation projects, and how location specific implementations are handled in regional business units.

RESULTS/CONCLUSIONS