bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operators Gain Significant Operational and Safety Gains with Remote Data Acquisition and Virtual Rig Presence
Authors: Cannon Katherine , Clarke Kieran , Muhi Namir , Davies Jonathan 
Published: September 2011

Abstract
Today's exploration and production operations in offshore environments face increasing limitations on bed space and restricted evacuation capability. Manning operations the traditional way is no longer an option. Remote operations pose a feasible alternative which brings equally important additional benefits. This paper describes the technical and personnel considerations of developing and deploying a remanned solution for wellsites and also reviews the challenges and successes of doing so as a standard approach to wellsite operations with specific emphasis on remote data acquisition and monitoring.
Remanning can occur in varying degrees from remote data gathering to expert assistance of wellsite personnel, through personnel reduction up to complete removal. A case study for remanned data aquisition in Asia Pacific is analyzed. This deployment required the complete removal of mudlogging staff from the wellsite. This paper details the changes in roles and responsibilities, re-engineering of processes and challenges overcome which led to a successful implementation.
The implementation of a remote data aquisition service was a complete success. Virtual-presence of data engineers via integrated video and radio over intranet solutions and implementation of VPN solutions using advances in communications technology allowed optimum use of globally distributed expertise. These solutions provided the operator with significant additional benefits. Mudlogging rig footprint was reduced to zero while improving service quality through real-time decision making and instant geosciences analysis. Operational cost savings with reduced travel and support costs were achieved, in addition to the expected reduction in HS&E exposure.
The current emphasis on remote monitoring, support and data recording capabilities allied with pressure from operators and regulators to remotely deliver O&G services and increasing speeds of developing ICT. We can expect to see a dramatic shift in the traditional way of providing wellsite services. Remanning is an effective solution that has proven its capability; however, is still only implemented sparingly. With a focus on safety and efficiency, virtual staffing will become the standard over the coming years; here we include some of the furture developments that will need to be achieved to make this a reality.
Problems with Operational Pigging in Low Flow Oil Pipelines
Authors: Combe Douglas , Hair David 
Published: September 2011

Abstract
Pigging of pipelines within the oil industry has been around for well over 100 years and has been used as the preferred (if not the only) internal method for cleaning, maintaining operational efficiency, data gathering and inspection for integrity management purposes.
The benefits in carrying out routine "operational" pigging cannot be underestimated and operational pigging to remove water, wax, scale and other debris which is formed during routine operations whilst transporting crude oil and gas is paramount in maintaining the integrity of any crude oil and gas pipeline system. The build up of such debris is common whether the pipeline is offshore between production platforms, from a production platform to onshore or a totally land based pipeline.
Similar problems are encountered to varying degrees dependent on pipeline size, location and type of the crude product being transported.
Pipelines are normally designed for a specific maximum flowrate, this maximum rate is generally maintained on a "plateau" for several years of a field’s life, during which routine pigging operation presents little or no real problem to the pipeline operator. The cleaning pigs which are used are generally designed for the "maximum" of "potential flowrate" which the pipeline is due to see during it’s plateau phase of operation. This assumption, that these pigs will be suitable for the life of field operations, is common place with pipeline operators and as such there is a significant increase in the risk that pigs will become "stalled" on a regular basis or potentially "stuck" causing significant disruption to operation, production and in the worst case scenario a very costly subsea intervention. As can be seen from Industry Analysts1 there will be a decline in overall oil production not just from the UK Sector but from the North Sea Basin and Europe as a whole. Therefore the need to understand pigging operations in "low flow" modes of operation cannot be stressed highly enough.
Cement Zonal Isolation to Control Salt and CO2 in Brazilian Ultra Deep Water Presalt Well of Santos Basin
Authors: Gomez Julio , Passos Alexandre , Melo Alexandre 
Published: September 2011

Abstract
Brazil deepwater reservoirs in the presalt area of Santos basin are typically thick hydrocarbon- and water-saturated limestones. Long-term zonal isolation is required to correctly exploit the reserves, to effectively perform stimulation operations and to control water and / or unwanted gas production.
For the case presented, CO2 is expected to be produced commingled with the hydrocarbon production. Also, salt formations are present at the top of the production zone. Thus, the cement needs to include both CO2 corrosion control and salt control in order to provide long-term zonal isolation, as well as to protect the well?s casing tubulars from corrosion and from the salt-driven stresses.
This paper describes the methodology used to design a salt - and CO2 - control cement slurry, the laboratory testing performed to meet the cement requirements and the field implementation of the designed zonal isolation for a well in ultradeep waters of Santos basin. In addition to a salt layer of more than 1,000 m, the challenges for the cement sheath included gas migration and compressive strength retrogression.
Creating a World Class Safety Culture Where Two Cultures Collide
Authors: Callen K.. 
Published: September 2011

Abstract
Creating a world class safety culture is difficult under any circumstances. Creating one culture when two distinct cultures exist is a bigger challenge. This paper is designed to provide a roadmap for how to bring two cultures together to act as one.
The Expatriates and Brasilian cultures have many similarities as well as differences. The challenge comes down to "How do you have these conversations when you do not speak the same language?" Both sides have legitimate merits for not speaking each other's language, yet there is a conflict in the perspectives. This is not a one-dimensional issue. It is not a "nice-to-have solution". It is a safety and operational issue for both contractor and operator with both human monetary cost. Once we agree on these points, both sides have to take steps.
What we did was have each person commit to learning 30 words of the other person's language. We kept it real, simple and personal. Expatriate drill crew members were asked to make a list of what 30 words, or phrases, do we need our Brasillian co-workers to know in English that would help the safety and efficiency of the drilling operations. Their Brasillian counterparts did the same for the Ex-pats. We repeated this with all disciplines on the rig. The results were fascinating. Not only did they learn the 30 words (116 people, 81% of the crew were successful) most people went beyond 30 words. The result was more than improved communications and understanding, there was a unified culture of "us". In conclusion the concept worked because learning 30 words was a stepping stone to bigger things. Once people started to use these words; risk assessments, the use of "Para" and safety conversations became more efficient with the increased communication. This has led to more personal conversations about family and career aspirations.
The significance is that you cannot create a world class safety culture when you have two cultures that are not integrated. Once the cultures come together, this sets the stage for developing a world class safety culture. The operator, contractor and individuals get a "win-win-win".
Getting Software Risk Mitigation Right from the Start
Authors: Fesas Nestor , Shafer Don 
Published: September 2011

Abstract
Software is the most invisible and one of the largest risks on high-specification offshore assets. For example, 40 – 56% of NPT is comprised of control systems software and hardware integration problems.1 These problems are often caused by insufficient contractual software specifications and inadequate audit and test activities which leave your assets vulnerable to risks associated with software failure including non-productive time (NPT) and health, safety and environmental (HSE) incidents.
Implementing proven methods for software risk identification, tracking and mitigation early in the asset lifecycle can help reduce these risks. A lifecycle approach (from design through to operations) helps ensure that control systems software functions as intended. Ultimately, this helps to reduce the risk of HSE incidents and prevent the additional remediation costs that can be incurred when software issues are not identified early.
This presentation will include real-life examples and will focus on lifecycle methods for reducing software risk. Topics will include: Implementation of contractual language that supports the ongoing performance of your control systemsDetermining and tracking control systems software requirements early in the lifecycle and why this activity is crucial to ongoing software risk mitigationDevelopment of effective plans for identifying and reducing software risk during operations
Integrated Management and Visualization of Unconventional Resource Evaluation Data
Authors: Cheng Kun , Wu Wenyan , Holditch Stephen A. 
Published: September 2011

Abstract
Information is key to evaluating the unconventional resources both with regard to characterizing the properties of geologic and petroleum systems, but also to estimating the potential of different resource types. The complex requirements for the data include: 1) integration of data with multiple types (e.g., basin general data, petroleum system data, and resource volume data), 2) display of the different patterns or correlations among the data (e.g., value distributions, geologic relationship, and geographical profile), 3) interpretation of data evaluation (e.g., numeric functions, evaluation models, and result meanings). Therefore, it is important to maintain a well-organized representation and management of data for better evaluation and decision-making.
In this contribution, the paper presents results of a resource evaluation system where the visualization method is thoroughly utilized not only to display and analyze data over multiple patterns and functions, but to enable users to clearly and easily manage data that have different types and relationships. The study was performed on a database that contains large volume of data about 25 North American basins having significant unconventional resource development. Here detailed, integrated data analysis was required for analog analysis and resource estimation to evaluate frontier basins. The solution was realized based on an integration of data visualization, management, and analysis using newly developed technologies.
It is shown that the integrated visualization and management of evaluation data helps discover the insightful relationships and patterns in different perspectives or scales, which is unattainable by traditional histograms or plots. Visualized data analysis and views highlight important results and critical factors of identifying analog basins while allowing the users to generally understand the large volume of data. In addition, the designed model enables users to manage data more efficiently, and supports the better understanding and transfer of knowledge.
Applying LWD Evaluations to Mitigate Horizontal Borehole Instability – A Case Study
Authors: May Dale H. , Kok Jeffrey , Birchwood Richard , Han Shim Yen , Peternell Ana , Blyth Matthew , Estep Nathan , Zabaldano John , Osman Haytham 
Published: September 2011

Abstract
In the quest to develop shale gas reservoirs, horizontal wells have emerged as the most prolific producers with lateral sections ranging from 3,000 ft to more than 10,000 ft in length in some plays. Even with substantial experience in planning and drilling in shale, borehole stability problems while drilling continue to occur, resulting in increased operating time and costs. Adding logging-while-drilling (LWD) tools to the drilling program can assist with identifying and mitigating such problems by providing valuable information on the condition of the wellbore. These measurements include ultrasonic and azimuthal calipers computed from density and photoelectric factor measurements. In this case study, time-lapse evaluation of these logs by logging on a trip out of the well revealed the presence of breakouts within the borehole and evidence of deterioration of borehole quality with time. Caliper measurements were integrated with other logs and regional tectonic information to construct a Mechanical Earth Model (MEM). The MEM consisted of estimates of rock mechanical properties, formation pressure, and in situ stresses. Using this data, a wellbore stability model was developed. The model provided insights into the stress regime and the mechanism of borehole failure. Drilling procedures to mitigate borehole breakout were consequently developed, thereby improving the efficiency of subsequent drilling in the same area.
Standards Address the Challenges of Drilling Automation
Authors: Shields John 
Published: September 2011

Abstract
Sophisticated applications are now available to analyze the drilling process and provide advice on the optimum operating parameters to drill safely, efficiently and to maximize wellbore productivity. The use of these applications requires a great deal of cooperation and collaboration between drilling contractors, service companies and operator personnel and systems.
Data must be exchanged between rig instrumentation systems, other rig sensors operated by service companies, downhole measurement systems, analysis applications and control systems. This data exchange must occur reliably and efficiently between different hardware systems and operating platforms.
Over the last few years a number of standards have emerged in the IT world, in industrial automation and in the oil industry. The use of these standards has the potential to bring in new levels of drilling automation capability. There are however some gaps and overlaps in the functionality and application of these different standards and an effort is required to bring these to the stage that they can be implemented and operated together efficiently.
This paper provides an overview of the work performed so far in various areas of standardization and presents some recommendations and guidelines for future development and adoption of standards that will enable reliable interoperation of drilling automation systems components.
A Multi-Domain Approach to Understanding Microseismic Data in a Tight Gas Play
Authors: Cherian Bilu V. , Villalobos Jeffrey M. , Cooley R. Duke , Panjaitan Maraden L. 
Published: September 2011

Abstract
In fluvial, multi-layer, tight-gas program, the acquisition of microseismic data together with the development of stress models and production models can significantly influence a development program. Often, the lack of data gathering pre and post microseismic acquisition introduces knowledge gaps that demonstrate inconsistencies between the various engineering domains. In this study, varying completion strategies and monitoring techniques were implemented together with postfracture modeling and production modeling (via rate-transient analysis techniques) to understand and explain the location of microseismic events.
This paper presents the agreements and differences observed between the stress models developed (and fracture diversion/limited entry observations), fracture half-lengths (from fracture modeling and production analysis), microseismic events and current geological understanding.
A New Analytical Method for Analyzing Production Data from Shale Gas Reservoirs Exhibiting Linear Flow: Constant Pressure Production
Authors: Nobakht M. , Clarkson C.R. 
Published: September 2011

Abstract
Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using square root-time plot, a plot of rate-normalized pressure versus square root of time. Linear flow appears as a straight line on this plot and the slope of this line can be used to calculate the product of fracture half-length and square root of permeability.
In this paper, linear flow from a fractured well in tight/shale gas reservoir under a constant flowing pressure constraint is studied. It is shown that the slope of square root-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure and formation compressibility. An analytical method is presented to correct the slope of the square root-time plot to eliminate the overestimation of fracture half-length. The method is validated using a number of numerically-simulated cases. As expected, the square root-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly-developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully-analytical, results in an improvement in linear flow analysis over previously-presented methods.
Comparative Study of Formation Evaluation Methods for Unconventional Shale-Gas Reservoirs: Application to the Haynesville Shale (Texas)
Authors: Ramirez Thaimar R. , Klein Jim D. , Bonnie Ron J. , Howard James J. 
Published: September 2011

Abstract
Petrophysical evaluation methods for shale-gas plays include mineral-based workflows that use traditional nuclear, electrical, and acoustic measurements in combination with advanced geochemical logs. This approach seems to offer the most comprehensive petrophysical analysis for unconventional reservoirs as it seeks an integrated characterization of mineralogy, organic content, porous volume, and fluid distribution. However, this method requires a significant input data set and key model parameters that may not be well known e.g. mineral elemental weight fraction end points. We anticipate variability in geochemical modeling results may arise between operators and service companies, using different model(s) and parameters, or where cross-validation with core data is not possible. The role of geochemical modeling must also be understood in the context of field-wide application, as these data are only infrequently acquired.
We discuss results from three interpretation techniques applied in a Haynesville well (Texas) that were calibrated to core analyses from crushed-rock (GRI) methods. First, a multi-mineral approach that includes the standard logging suite and geochemical logs shows that independent petrophysical assessments from two vendors and those from in-house analysis are not in agreement. Second, a petrophysical model that uses resistivity and a combination of two porosity logs is proposed when only these log measurements are available. This model is readily extended to many wells with a common logging suite and may be applied in horizontal boreholes. Third, given sufficient core data across multiple wells, we apply a cluster analysis technique that provides robust results suitable for large regional studies. We compare results from each method to available core measurements and provide recommendations for further applications.
In this paper, we also study the role of laboratory NMR measurements to support reservoir characterization of shale gas. Laboratory NMR measurements on preserved core samples are performed in the "as-received" state. Core NMR porosity and water saturation values are significantly different from those of the crushed-core analysis. This observation suggests that additional laboratory NMR measurements may be required for log calibration.
The work described here provides an independent and critical analysis of multiple formation evaluation techniques applied to a Haynesville shale well with core and extensive log measurements. Results highlight the difficulty in developing a mineral-based model using geochemical logs that is consistent with both core and vendor deliverables. Interpretation of NMR data remains an elusive opportunity requiring mostly unknown formation-specific evaluation parameters.
Factors Affecting Hydraulically Fractured Well Performances in the Marcellus Shale Gas Reservoirs
Authors: Osholake Tunde , Wang John Yilin , Ertekin Turgay 
Published: September 2011

Abstract
Development of shale gas reservoirs has become an integral part of the North American gas supply. The Marcellus shale formation contains large amount of natural gas resources and its proximity to high demand markets along the East Coast of the United State makes it an attractive target for energy development. The economic viability of such unconventional gas development hinges on the effective stimulation of the low permeability reservoir rocks.
Horizontal wells with multi-stage hydraulic fracturing treatments are the stimulation method of choice and have been successful in shale gas reservoirs. However, the fundamental science and engineering of the process are yet to be fully understood and hence the stimulation method needs to be optimized. In this paper, we used numerical reservoir simulation techniques and quantified the effect of the following pertinent factors on the well performances and long-term gas recovery: multiphase flow, proppant crushing, proppant diagenesis, reservoir compaction, capillary pressure, and operating conditions. The knowledge generated in this study enables engineers to better design fracture treatments and operators to better manage the wells in the Marcellus shale gas reservoirs.
Application of Propane (LPG) Based Hydraulic Fracturing In The McCully Gas Field, New Brunswick, Canada
Authors: LeBlanc Don , Martel Tom , Graves Dave , Tudor Eric , Lestz Robert 
Published: September 2011

Abstract
New Brunswick Canada's first commercial unconventional gas field, the McCully field, is located near the town of Sussex in southern New Brunswick. The field is comprised of low permeability Hiram Brook sandstones as well as the underlying Frederick Brook shale. The McCully field started producing gas from the Hiram Brook in April 2003 from two wells and was followed by full production in June 2007. Currently there are twenty-nine wells producing from the Hiram Brook.
The Frederick Brook shale was placed on production in March 2008 and is producing gas from one hydraulically fractured vertical well. Additional wells have been drilled, hydraulically fractured and flow tested to further evaluate the development potential of the shale.
Prior to 2009, development of the McCully field has included the use of water based hydraulic fracturing to enhance production. In 2009 a fracture program based on using LPG as the fracture fluid was undertaken. Both the Hiram Brook sands and the Frederick Brook shale have been hydraulically fractured with LPG and the results have been compared to the performance of the water based fractures performed in the past.
It has been found that both clean up and initial well performance for these tight sands were significantly enhanced using LPG fracs rather than water fracs. This paper compares the clean up performance and the initial flow performance for wells fractured using the two fracturing methods.