bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flexible Core Sample Acquisition Program for Deepwater, Offshore Brazil
Authors: Romero P.. , Lofts J.. , Lovera O.. , Georgi D.. 
Published: September 2011

Abstract
Deepwater operations (with high rig spread rates) like those offshore Brazil require an operator to very carefully consider the benefit-versus-cost of a full coring acquisition program. Yet, core-based information is invaluable in the exploration phase of a field's potential, and the basis of thoroughly understanding reservoir rock potential (petrophysics) is founded on these core measurements. With the drive for cost efficiency, conventional full-core acquisition is often curtailed and subsurface teams must rely on percussion or rotary sidewall core samples. This choice is made even though it is known that for many core analysis measurements, the accuracy of the measurement is directly proportional to the pore volume.
A new rotary sidewall coring technology applicable for deepwater environments has been applied offshore Brazil that enables the recovery of more than three times the core volume when compared to cores recovered with standard rotary coring tools. The resulting increase in pore volume positively impacts the accuracy of the core porosity measurement and other measurements that depend on pore volume (e.g., capillary pressure, water saturation, and SCAL measurements, in general). Recovery of up to 60 samples during a single trip in the well is achievable, enabling a good lithology sample spread in one acquisition. Acquisition time per core is more than three times faster that of the previous-generation rotary coring tools, resulting in significant reduction of coring time, especially for offshore operations. Coupled with a new bit design, optimized to take advantage of the increased rotational speed, cores can be cut at even higher levels of overbalance pressure (&gt; 1,000 psi [6.89 MPa], depending on porosity and permeability). The ability to take up to 60 larger-volume cores in one run provides operators, like those in deepwater operations of Brazil, the flexibility to continue to vary the design of core acquisition programs to meet the benefit-versus-cost dilemma of full-core acquisition. They also enable much better contingency data gathering if full-core programs are not successful.
Large-Bore Expandable Liner Hangers Significantly Improve Operational Cost in a Deepwater Gulf of Mexico Well
Authors: Johnson M.. , Ardoin K.. , Bullard B.. 
Published: September 2011

Abstract
When drilling offshore wells, well-bore architecture will typically require casing strings larger than 13-5/8-in. to be "hung-off in the casing hanger located at the wellhead. To date, this has been the most widely used method, albeit a time consuming and usually costly approach. With solutions needed to alleviate these issues, a new expandable technology has been developed as an alternative to the conventional approach.
An expandable large-bore liner hanger that allows an operator to set a liner instead of a full string of casing has recently been designed. Plans for operations within the Gulf of Mexico region began after successful applications of the new large-bore expandable liner hanger were run in other parts of the globe. With internal diameter restrictions coming into play at the wellhead in the Gulf, the original product required some design modifications.
The contents of this paper will cover the development and successful installation of the first large-bore expandable liner hanger (LBELH) in deepwater Gulf of Mexico operations for ENI's Triton well. Advantages in this installation included casing placement flexibility, redundant seals at the top of casing, improved load support reliability, the capability of rotation and reciprocation during cementing, cost reduction, elimination of requiring the casing hanger to seal in the casing adapter, and complications with shallow deviation.
Due to the successful installation of the large-bore expandable liner hanger, the customer was able to save on costs of 2,300 feet of 16 in. casing, greatly improving economics for the project. With the slick-bore design of the system, equivalent circulating densities were greatly lowered. Coupling this feature with the capability to rotate and reciprocate during cementing greatly improved the cementing quality, as well as run-in speeds, with no mud loss. These two features are expected to increase well life and reduce future remedial work to the well.
By eliminating the requirement to properly and precisely space out liner jobs on floating rigs in deepwater regions, pressure integrity issues of conventional systems can be avoided.
Advanced LWD Imaging Technology in the Niobrara – Case Study
Authors: Koepsell Randy , Han Shim Yen , Kok Jeffrey , Munari Michael , Tollefsen Edward 
Published: September 2011

Abstract
The Niobrara formation is an increasingly active exploration target in the Denver-Julesburg basin that contains both reservoir rock and source rock. The reservoir rock consists of up to four laterally continuous chalk benches and the source rock is comprised of three organic-rich interbedded shales. Both permeability and porosity in the Niobrara chalk are relatively low and production is expected to be enhanced by natural fractures related to: horst and graben structures, dissolution of evaporite beds, wrench faulting, listric faulting, regional stresses, and pore pressure. To develop the Niobrara formation, horizontal drilling combined with multistage hydraulic fracturing increasingly is used. To enhance reservoir understanding and optimize field recovery, advanced logging-while-drilling (LWD) services are now available for real-time acquisition and transmission of high-resolution electrical images of the borehole, azimuthal gamma ray, and multi depth measurement of formation resistivity. Analysis of this information in real time with high data rate LWD acquisition telemetry allows proactive well-placement decision making by comparing apparent dip of the formation to the borehole trajectory. This is effectively used for maximum reservoir contact of the lateral wellbore in the desired chalk bench. In addition, the analysis of the high-resolution images facilitates fracture identification, fault estimation, and structural analysis for the optimization of stage designs for hydraulic fracturing. This paper will expand the use of LWD with high-resolution image interpretation, formation evaluation, fracture system analysis, and structural analysis for the purpose of drilling better-performing wells through optimized well placement and hydraulic fracturing operations.
Building Real-time, Remote Pressure Management Service Capability to Enhance Safety and Reduce Drilling NPT
Authors: Sadlier Andreas , Wolfe Chris , Reese Mike , Kenda Bill 
Published: September 2011

Abstract
As drilling environments become more challenging and complex, the need to increase safety margins and reduce drilling non-productive time (NPT) costs continues to intensify. It is also likely that our industry's future will face greater pressure from regulators and the public to ensure safer drilling practices. More and more operators are turning to remote surveillance services as a way to provide real-time interactions with wellsite personnel to mitigate drilling hazards.
Through remote monitoring services, dedicated personnel can actively monitor multiple operations and spot potential problems that busy rig hands mightotherwise overlook or lack the specialized training to recognize. In addition to the health, safety, and environmental benefits of fewer personnel on location, remote service engineers/specialists can easily collaborate with a team of experts located in an offsite center of excellence, providing greater wisdom for real-time decisions compared to any one person at the wellsite.
Developing a value-added remote service from scratch requires many elements for success. For example, providing a remote, real-time integrated pressure management service requires careful planning and development of service components. These include facilities and communications infrastructure, software and data-management tools, clearly defined service integration processes and communications protocol, trained and available personnel for job execution, and customer partners willing to field test service solutions.
This paper offers a case study on how a successful remote, real-time integrated pressure management and wellbore stability service has been developed in the US Gulf of Mexico. It discusses the various aspects of the service's development from defining the service objectives, components, and deliverables to the communications protocols and the personnel competencies and training requirements for staffing. It also describes aspects of the physical facilities, communications infrastructure, and real-time software tools that provide automated alarms, which aid personnel in keeping the drilling operation out of trouble. Finally, a customer field trial that helped to improve the service further is examined and a brief summary of future developments is provided in the paper.
Sensors and the Way Forward for Sensing Efficiently and Effectively
Authors: Aminzadeh Fred , Al Yateem Karam , Puecher Leonardo 
Published: September 2011

Abstract
Sensors provide engineers with the necessary data for their day-to-day activities and assure smooth operation, monitoring wells and equipments in a field. Almost every new well drilled has a number of sensor during the drilling and completion. Sensors are an integral and vital part of the digital oilfield and the real time monitoring, and control. These are all simple requirements for the intelligent filed in order to better understand the well performance and ensure safe and efficient operation. They are most beneficial in remote areas where HSE is of a major concern. They optimize the placement of new drillings and work over sidetracks through making it possible foreseeing change in real-time, supporting the initiation of a remedial action in case of anomalies occurrences. Overall, their existence in any reservoirs optimizes the ultimate oil recovery.
This paper will discuss the general history of sensing along with their oil industry record. We will focus on the established methods of-well-sensing, as well as the current issues, capabilities, requirements, and visualization. Data mining and integration of sensor data using soft computing technologies is of paramount importance. The paper will address their various functions, signal type, robustness, technical background and the purpose of placement. It will also discuss communication infrastructure, networking, and reliability challenges. The focus will be on In addition, we will provide an in-depth investigation of various types of sensors and their functionality, advantages and drawbacks. We will also illustrate desired smart network embedded system/module and wireless systems. We will conclude with examples of oilfield applications, lessons learned and future trends.
Modeling, History Matching, Forecasting and Analysis of Shale Reservoirs Performance Using Artificial Intelligence
Authors: Mohaghegh Shahab D. , Grujic Ognjen , Zargari Seed , Kalantari Masoud 
Published: September 2011

Abstract
Producing hydrocarbon from Shale plays has attracted much attention in the recent years. Advances in horizontal drilling and multi-stage hydraulic fracturing have made shale reservoirs a focal point for many operators. Our understanding of the complexity of the flow mechanism in the natural fracture and its coupling with the matrix and the induced fracture, impact of geomechanical parameters and optimum design of hydraulic fractures has not necessarily kept up with our interest in these prolific and hydrocarbon rich formations.
In this paper we discuss using a new and completely different approach to modeling, history matching, forecasting and analyzing oil and gas production in shale reservoirs. In this new approach instead of imposing our understanding of the flow mechanism and the production process on the reservoir model, we allow the production history, well log, and hydraulic fracturing data to force their will on our model and determine its behavior. In other words, by carefully listening to the data from wells and the reservoir we developed a data driven model and history match the production process from Shale reservoirs. The history matched model is used to forecast future production from the field and to assist in planning field development strategies. We use the last several months of production history as blind data to validate the model that is developed.
This is a unique and innovative use of pattern recognition capabilities of artificial intelligence and data mining as a workflow to build a full field reservoir model for forecasting and analysis of oil and gas production from shale formations. Examples of three case studies in Lower Huron and New Albany shale formations (gas producing) and Bakken Shale (oil producing) is presented in this paper.
Drilling Automation: An Automatic Trajectory Control System
Authors: Pirovolou Dimitrios , Chapman Clinton D. , Chau Minh , Arismendi Hector , Ahorukomeye Mbaga , Penaranda Juan 
Published: September 2011

Abstract
In the last decade, the oil and gas industry has witnessed the emergence of rotary steerable systems (RSS) that led to certain achievements that were not possible with conventional mud motors. Rotary steerable systems enable faster drilling, smoother wellbores, and extended-reach drilling (ERD).
Still, a drilling assembly built around an RSS tool is sensitive to factors such as bit type, operating parameters, type of drilling fluid, lithology, and borehole diameter. Therefore, it is not always optimal for a human operator (typically a directional driller) to select and issue the right commands to the drilling tool at the right time. This situation becomes even more challenging when those decisions have to be made in a matter of minutes.
Steering the well accurately is paramount to geo-steering, optimal well placement in the reservoir, and anti-collision.
This paper discusses a new system that monitors all real-time data that is available, "learns" the steering behavior of the drilling assembly, and uses the acquired information to create more accurate projections for the directional driller. The system recommends the optimal command to direct the drilling tool according to plan.
This tool is currently being used by a number of field locations as an advisor. The next version of the system, being field tested, autonomously issues downlink commands directly to the RSS tool, making it an automatic trajectory controller. The concept is very similar to the autopilots used in commercial airplanes today. The anticipated value from this technology is better service quality and higher performance that can be delivered predictably and consistently.
Preliminary results look very encouraging. During the evaluation period, the system has accumulated approximately 5,000 running hours, corresponding to approximately 72 runs. These tests are in various hole sizes and well profiles, using different RSS tools.
An Improved Methodology to Obtain the Arps’ Decline Curve Exponent (b) for Tight/Stacked Gas Reservoirs
Authors: Yu Shaoyong 
Published: September 2011

Abstract
Production performance forecasting and the estimated ultimate recovery (EUR) evaluation are two of several uncertainties in the study of tight gas reservoirs. Using the Arps’ decline curve analysis to extrapolate the estimated ultimate recovery (EUR), based on the future production forecasting, is still a widely employed engineering tool in the oil and gas industry today. Tight gas reservoirs usually have a long transient/transitional flow period due to its low permeability. Simply by using the best fit "b" value to estimate the best EUR could generate an error as much as 100% from the true EUR. There has been a number of technical papers published dealing with this issue.
This paper will present a new improved methodology to determine a more accurate "b" value to be used in the Arps’ decline curve analysis for tight gas reservoirs. This new approach, using a newly developed relationship between Qcum, Qcum, t→∞, qt and t, is more rigorous and much easier to use in comparison with all other existing ones. This new improved methodology will not only make future production forecasting more accurate, but also estimate the original-gas-in-place (OGIP) controlled by the well much easier.
In Western Canadian Deep Basin, there are many extremely "tight" gas reservoirs that consist of multiple stacked shorefaces. Permeability in each shoreface varies very significantly, generally with the upper shoreface having a better permeability and the middle and lower ones having a permeability as poor as 0.01 mD. By using a reservoir simulator, a number of simulation runs have been performed by the author to answer the following questions:
Could Fetkovich's b-values recommendation (mostly b&lt;= 0.4 ~ 0.5 for single gas layer, b&gt;=0.5 for multi-layer without crossflow) still be applied to the tight gas reservoirs? In a multi-stacked shoreface reservoir, does the lower perm zone contribute to the overall production? Moreover, how and when will it influence the production profile? When using the Arps’ decline curve analysis, what are the reasonable b-values to be used for the tight/stacked gas reservoirs?
Both synthetic production decline profiles generated from simulation runs and a field example are presented in this paper to illustrate this new proposed methodology and to answer the above three questions.
Leveraging a Technical Domain Taxonomy to Enhance Collaboration, Knowledge Sharing and Operational Support
Authors: Perry Phil , Wise Wade , O'Neill Dennis , Jensen Mary 
Published: September 2011

Abstract
The E&P industry is a highly technical and complex world which is inhabited by skilled professionals of many different specializations and backgrounds working all over the globe. In order for an organization to perform effectively, it is very helpful to have a shared view of that world and a common vocabulary to describe its artifacts, processes and challenges.
Over the past two years, we have developed a multi-faceted taxonomy that describes the realm of technical services in the upstream E&P domain. It comprises the areas of E&P disciplines, application methods and environments, technical services, and problem diagnoses.
This taxonomy is finding wide use within our technical communities and has been embodied into computer-based applications in the areas of collaboration (workspaces and wikis), knowledge capture, expertise identification, field technical support and "smart" enterprise search.
This paper discusses our methodology in establishing and reviewing the E&P taxonomy within a large technical community and how we are applying it to solve real-world business problems.
Reducing Complexity: A Case History of De-manning Traditional While Drilling Wellsite Services
Authors: Dwyer James , Swanson Aaron , Laing Moray , Brady James 
Published: September 2011

Abstract
All technology and new concepts evolve at different rates. Adoption is driven or slowed due to costs, complexity or accessibility. This was true for the automotive industry, computers and is also true for the digital oilfield. Using travel as an analogy it is easy to conceptualize technology adoption hurdles that have occurred. The evolution of getting from one place to another changed from travel by foot to traveling by car. Similarly the evolution of information and data transfer evolved from hand writing or the use of a type writer into the computer and digital age. In fact our industry has undergone its own evolution to help improve the extraction of hydrocarbons. One such evolution in our industry has been slowed. This is the movement of personnel from the well site to the web site.
With the growth of the global oil industry, there is a greater need to have experienced personal monitoring and analyzing the real-time data that is gathered. This growth in demand has lead to a vacuum in availability of experience necessary to perform this analysis on a daily basis. To fulfill this global void, the accessing the data and rig site remotely came into play more than 20 years ago.
Although this concept of removing the personal from the rig site isn't a new one, recent increase in technological capabilities of communication, increases in the complexity of data sets, and an increase in the quantity of experience personal have driven the industry to relook at the option of remote utilization. This paper will not detail the big crew change or attempt to promote the value of the movement of personnel from the well head to the office. Rather this paper will provide, by means of a case history, an example of how to reduce the complexity involved well site ‘demanning’. The case will illustrate a simple staffing and support methodology. The case will illustrate what was done, technology used to effect the change and describe the outcome
Radio Frequency Identification of Remotely Operated Horizontal Frac
Authors: Tough John , Mason Jane , Biedermann Randal , Visotto Al 
Published: September 2011

Abstract
There is a very significant move today towards multiple zone fracturing operations in a single well where zones are separated and individually fractured, particularly in shale gas completions. This technique has to date involved the use of ball seat activated sliding sleeves located across each zone, with consequent reductions in internal diameter (ID) and attendant flow characteristic limitations or selective perforating, fracing and isolation with a bridge plug in a cemented casing string while working up the hole. Both approaches involve many downhole intervention operations such as perforating, shifting sleeves, running plugs and subsequently milling them up with coiled tubing (CT) intervention, all of which extend the length of the operation and add to the overall costs.
To simplify the process of multiple fracturing operations, especially in open hole, a new approach has been designed which uses Radio Frequency Identification (RFID) techniques to remotely operate sliding sleeves. The number of sleeves that can be run in a well using this technology is essentially unlimited, each one having the same ID and a unique electronic address which allows it to be operated remotely at will. This approach provides for a means of making considerably more zones available for treatment without physical intervention with CT or wireline and thereby speeds the multiple frac operations and allows for wellbore clean up from the toe to the heel of the well.
In this paper the authors will describe the design and operation of the RFID operated frac sleeves and the advantages they provide. They will go on to detail the Worlds’ first remotely operated horizontal openhole frac completion where frac sleeves and swell packers were used in an extended reach horizontal shale gas well.