bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multidisciplinary and Integrated Methodology for Deep Water Thinly Bedded Reservoirs Characterization
Authors: Nurhono Achmad A. , Kantaatmadja Budi P. , Masoudi Rahim , Thu Goh Sing , Rahman M Nasir , Othman Mohamad B , Hernandez Nina M. , Rahman M. Ramziemran 
Published: October 2012

Abstract
The sedimentation in deepwater environments commonly includes deposition of thinly-bedded pay zones that are difficult to be characterized using standard seismic and logging techniques. Furthermore, these zones are often left unexploited and even overlooked during drilling, as they are finer in resolution than it can be detectable in conventional open-hole logs.
The paper presents an integrated multi-disciplinary study on thinly-bedded reservoir characterization in deep water areas in Malaysia. The adapted workflow consist of: (1) Seismic Data Conditioning, (2) Petrophysical SHARP Analysis, (3) Simultaneous and Rock Model Building, (4) Lithology Prediction, Hydrocarbon Volume, and Net pay, (5) Stochastic Seismic Inversion and Geo-statistical Modeling, and (6) Reservoir Simulation and Validation, (7) Uncertainty Analysis, (8) Sedimentological Analysis using Core-Image, and (9) Geomechanical Rock Property Analysis.
Petrophysical diagnostics using high quality resistivity images of OBMIs, as log input for thinly-bedded modeling, was the primary driver to establish effective elastic properties through AI vs. VP/VS cross plot (for lithology prediction) and AI vs. total porosity cross plot (for porosity prediction) within the model. These cross-plot transforms are then upscaled and applied to build a cascading of deterministic inversion (simultaneous AVO inversion) and stochastic inversion of 1-ms sampling, which are calibrated to core and neural network litho-facies interpretation for lithology and porosity modeling.
The geo-statistical modeling workflow was initially built-in with 7 exploration wells that have OBMIs (Oil Base Micro Imager) as the typical model. Numbers of reservoir properties realizations were generated by generating geo-cellular grid over the zone of interest. These realizations could provide an improved lithology, porosity and fluid determinations and could lead to estimate a more robust volumetric, particularly within such thinly-bedded reservoir. The developed unique integrated workflow was applied on the field under study showing about 30% increase in in-place volume and was successfully validated against available production/well data as well as new drilled wells.
Technology Enhanced Online Learning for Drilling Equipment Improves Knowledge Transfer
Authors: Keable Kevin BP , Redlinger Thomas 
Published: October 2012

Abstract
As companies grow and spread their activities globally, so the adequate training of the resultant expanding workforce becomes an issue of major importance to ensure quality of performance is maintained. Our current global workforce is working under significant pressure to deliver tools, equipment and services to a high standard which has significantly increased the challenge of ensuring that all personnel are trained to the same standards and have access to the best information. Online learning programs or computer based training (CBTs) although providing consistency lack the utilization of video, animation, technical graphics and voice-over, which are essential to ensure good knowledge transfer and retention. So, with the current online training being considered insufficient a new approach needed to be initiated.
As a result a new series of innovative hybrid CBT courses has been developed which is focused on commodity drilling tools, pressure control equipment and safety, using interactive methods dramatically to improve the learning experience and knowledge transfer. The resultant courses were placed on the in-house learning management system and made available across the globe in multiple languages. A total of 12 modules have been created in the initial year of CBT course development, following which some 13,000 training modules have been taken representing an impressive employee acceptance of the process
In this paper the authors will review the development of this program and the process used to create its content and track performance. The objective of this paper is to transfer knowledge on the processes needed for the development of successful online training and to demonstrate its level of effectiveness.
Increased oil production at Troll by autonomous inflow control with RCP valves
Authors: Halvorsen Martin , Elseth Geir , Nævdal Olav Magne 
Published: October 2012

Abstract
Troll is a large subsea development offshore Norway. Oil is produced to Troll B and Troll C platforms from 120 long horizontal subsea wells completed in a thin oil column. Oil production is optimized within the gas handling capacity at the platforms and the challenge is to drill and complete the wells in a way that gas does not have an easy access into the well. Troll has focused on developing and implementing inflow control devices that limits gas coning. An autonomous inflow control device, the RCP valve, has been developed by Statoil and implemented at the Troll field. The purpose of the RCP valve is to restrict gas compared to oil. The valve adjusts the choking of the fluids depending on which phase (oil or gas) being produced. Currently three wells have been completed with RCP valves. Reservoir simulations as well as production experience show a significant increase in oil production. It is observed that a well completed with RCP valves has a significantly lower gas oil ratio development compared to other Troll wells.
Oil-Water Delineation with a New Formation Tester Module
Authors: Al-Otaibi S. H. , Bradford C. M. , Zeybek M. , Corre P.-Y. , Slapal M. , Ayan C. , Kristensen M. 
Published: October 2012

Abstract
Delineation of oil and water in heterogeneous carbonate formations can be challenging, especially in the presence of low resistivity formations and low mobility zones. Advanced wireline formation testers (WFTs) have traditionally been used in openhole logging for pressure profiles, coupled with downhole fluid analysis (DFA) and sampling for an integrated approach. It is often difficult to obtain well defined oil and water gradients with pressure measurements in tight formations, especially with probe-type tools. Straddle-packer modules are often used to enable flow from low mobility formations. However, the straddle-packer module has operational and differential pressure limitations, as well as a relatively large storage volume in the isolated interval.
A field example of oil-water delineation is presented for a low resistivity, heterogeneous carbonate formation. Low formation fluid mobilities required the utilization of a new wireline tester module over the standard probe type tool. A newly designed fluid inlet module with multiple openings was utilized across the low mobility zones for the first time in the industry. This new module avoids issues associated with the interval volume of a dual-element straddle-packer-type tool and provides significantly faster clean up from the formation. In addition, minimized storage results in better Interval Pressure Transient Test data. Faster set/retract operation of this tool and a much higher pressure differential limit are additional advantages over existing dual packer tools. Several station measurements with mobilities of less than 0.1 md/cp were conducted. This allowed oil to be identified across a low resistivity zone, leading to an increased oil column height in the field.
Results showed that more accurate oil-water delineation was provided using the new module along with high resolution optical fluid analyzers, identifying mobile oil from low resistivity carbonate zones. In addition, more accurate permeabilities for the tested zones were obtained through pressure transient data analysis.
Improving Production in the Marcellus Shale Using an Engineered Completion Design: A Case Study
Authors: Walker K. , Wutherich K. , Terry J. , Shreves J. , Caplan J. 
Published: October 2012

Abstract
To complete the Marcellus shale's horizontal wells simply and cost-effectively, operators typically use geometric perforation designs in order to prepare for hydraulic fracturing. With this technique, perforation clusters are placed at equidistant points along the lateral. However, microseismic monitoring shows that this type of stage selection often distributes hydraulic fracturing treatments unevenly. The fracture treatments propagate to the lowest-stress intervals, leaving a large number of perforations under stimulated or simply unstimulated. In an attempt to improve on this technique, a study was performed in which wells using an engineered perforation design were compared against offset wells that had a geometric perforation design.
For the wells employing an engineered design, an acoustic scanning tool was deployed on wireline and mechanical rock properties were obtained along the length of the productive lateral. The critical well information, including in situ stress, lithology, Young's modulus, and Poissons Ratio enabled engineers to create custom staging and perforating designs. These designs were optimized to provide more consistent stimulation along the entire lateral, and lower breakdown and treating pressures. The final result of using the engineered perforation design was a significant increase in production when compared to conventionally completed wells.
During the stimulation treatment of the engineered perforation design, there was a significant drop in the average treating pressures during fracturing when compared to geometric offsets. This was due to several factors including the fact that perforations targeted lower stress intervals. In addition to lower pressures, an elimination of premature job terminations or "screen-outs" was seen. This occurs when pressures increase to such a degree that the stimulation treatment cannot continue within acceptable pressure ranges. Previous treatments in offset wells yielded a 35% screen out rate which resulted in significant lost time and additional costs.
The process and production results of wells completed with geometric perforations to wells with engineered perforations.
Subsurface To Surface Microseismic Monitoring for Hydraulic Fracturing
Authors: Peyret Olivier , Drew Julian , Mack Mark , Brook Keith , Maxwell Shawn , Cipolla Craig 
Published: October 2012

Abstract
The options for acquiring microseismic data to evaluate hydraulic fracture treatments have expanded in recent years to include surface and near-surface monitoring. However, there has been an absence of detailed and comprehensive validation and comparison of the various monitoring techniques, leading to misconceptions and uncertainties concerning the different alternatives. Traditional downhole monitoring is constrained by the requirement for adequately located deep monitor wells, which limits application in exploration and appraisal and other areas without suitable monitor wells. Surface monitoring provides a means to gathering important microseismic data without the need for observation wells, although the validity of the results is sometimes questioned.
This paper presents detailed "side-by-side" comparisons of surface and near-surface monitoring techniques and provides guidelines for the application of the various monitoring options. This multi-year journey was undertaken by comparing several surface/near-surface data sets with their downhole counterparts in a series of concurrent surveys in US shale plays. These comparisons answer the following questions concerning sensitivity, attenuation, and location uncertainty of surface monitoring options:
How do the microseismic events detected and located at the surface or near-surface compare with those detected and located downhole? What is the best surface or near-surface design and what parameters are key to optimizing it? How does the processing and analysis of surface data compare with that of downhole data?
The paper includes a rare dataset from a field laboratory in the Fayetteville shale that was instrumented with a 4000 geophone surface microseismic array, a 5 Shallow Hole Grid, and traditional downhole microseismic arrays located in both vertical and horizontal observation wells. In addition, a 71-level geophone array was deployed from TD to surface in a vertical observation well. This multifaceted monitoring provided an unparalleled dataset to compare the various microseismic monitoring options.
The paper documents how and when the surface or near-surface technique provides a meaningful alternative to downhole monitoring both technically and economically, presents candidate selection criteria and provides a comprehensive comparison of the relative technical and economic merits of each monitoring option.
Improving the Accuracy of Directional Wellbore Surveying in the Norwegian Sea
Authors: Edvardsen I. , Hansen T. L. , Gjertsen M. , Wilson H. 
Published: October 2012

Abstract
Time-dependent current fluctuations in the Earth's ionosphere cause inaccuracies in wellbore directional surveying. These inaccuracies increase at higher latitudes and although monitoring and correction is possible, it becomes less valid as the distance between the monitoring site and the rigsite increases, a particular problem for offshore drill sites. The characteristics of the ionosphere currents indicate that the most favourable location for monitoring stations is on the same geomagnetic latitude as the drill site. Such an arrangement has been used to monitor and correct directional survey at the Haltenbanken area of the Norwegian Sea over a period of approximately two years. Haltenbanken is located about 200km west of the Norwegian coast at latitude 65° north, where magnetic storm activity can have a significant effect on directional surveying. A monitoring station was set up on the coast at the same geomagnetic latitude as Haltenbanken. To test the idea that magnetic disturbances are similar along constant magnetic latitude, an additional monitoring station was established 200km east of the main station. The data broadly confirmed the hypothesis, although isolated events were observed when this is not the case. The challenges of surveying at offshore sites north of 62° N latitude are probably greater than the oil and gas industry is accustomed to; challenges that will become more significant if the Arctic Ocean is opened to drilling operations. The technique described in this paper may contribute to safer and more productive offshore operations at high latitudes.
Investigation of Thermal Well Test Analysis for Horizontal Wells in SAGD Process
Authors: Ghahfarokhi Ashkan Jahanbani , Jelmert Tom Aage , Kleppe Jon 
Published: October 2012

Abstract
Steam assisted gravity drainage (SAGD) is the most promising technique in heavy oil recovery. Determination of the steam chamber volume is very important for monitoring the progress of this process. Thermal well testing offers an early method to estimate the steam chamber mobility and volume using pressure falloff tests. However, well test analysis of horizontal wells is more complex than that of vertical wells.
Pseudo steady state method is used to estimate the chamber volume from falloff testing assuming a composite reservoir. Due to the large contrast in the fluid mobility of the swept and un-swept zone, the flood front behaves as an impermeable boundary. Therefore, the steam chamber acts as a closed reservoir and the pressure response is characterized by pseudo steady state behavior.
The purpose of this work is to evaluate the feasibility and accuracy of thermal well test analysis for horizontal wells in SAGD process. Pressure falloff test is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Effects of several parameters like permeability anisotropy, steam quality, injection rate and time on well test results are also studied.
Results of this study show that steam chamber volume and mobility and skin factor can be reasonably estimated from pressure falloff tests, and are in good agreement with simulated results. Longer injection times prior to shut-in, prove to have an adverse effect on the estimated swept volume because of a more irregular shape of swept region and the possibility of early breakthrough. Irregular swept region shape, however, does not significantly affect the early time well test data. Calculated swept volume is highly sensitive to the ratio of vertical to horizontal reservoir permeability. Finally, higher steam quality results in more accurate estimations.
Case Histories Exploring the Economic Value of Solid Expandable Systems over the Life of the Well
Authors: Farley Douglas 
Published: October 2012

Abstract
From the early beginnings, the idea of expanding solid tubulars as a means to reduce nonproductive drilling time by covering unstable formations and pressure events while minimizing the telescoping effect of standard casing programs was thought to be the panacea over conventional well-construction techniques. However, the development and commercialization of this technology has been driven by increased production opportunities realized by improved well architecture and completion size optimization. Solid expandable systems are now commonly used in development, planning, drilling, and completion, and during production decline.
Global Chemical Evaluation Process Review to Qualify Regulatory and Environmental Characteristics for Oilfield Chemical Products
Authors: Daulton Dan , Post Matt , McMahon JoAnn , Kuc Bill , Ake Charles , Hill Denise 
Published: October 2012

Abstract
Environmental qualification of chemical products is a critical component of the oil and gas industry. However, regulatory and chemicals evaluation criteria, if available, are typically designed for local ecosystems and vary within specific regions and regulatory entities. Although some qualification schemes have been adopted across multiple geomarkets, there is a lack of uniform, globally coordinated, strategic objectives to address this issue for the industry. This has created disjointed, ineffective responses by vendors, chemical manufacturers, and suppliers involved in creating and delivering complex chemical solutions to meet oil and gas industry challenges.
Recent movements of international organizations sponsored by the United Nations (2009) have addressed communication of chemical hazards via the Global Harmonized System of Classification and Labeling (GHS/CLP). Adoption of GHS by numerous regulatory bodies has brought international consensus to hazard criteria and definitions. Implementation of GHS is proving to be long, slow, and arduous. Furthermore, the intended scope of GHS focuses on standardization of hazard communication. As such, the core elements of GHS are applicable to evaluating chemical hazards. However, several hazard endpoints are either inappropriate or need modification to address the unique needs of the oilfield chemical market. Therefore, it is incumbent upon global chemical suppliers to identify an effective chemical evaluation process. This process must facilitate the offering of product solutions which meet the performance demands of petroleum exploration and production, while protecting human health and the environment and complying with existing and future regulatory statutes, as well as specific local concerns. This paper describes our continued efforts to globalize the chemical evaluation for all oilfield products. Comparative scoring of chemicals is accomplished through a practical, transparent, and quantitative process, based upon their potential safety, health, and environmental impact. Since initially introduced, the evaluation process has been updated to include review of key global regulatory requirements (chemical prescreening, transportation, handling, and application). Benefits include:
Reducing redundant development efforts, Improving research and development focus using specific guidelines for regulatory and chemical hazard assessments, Enhancing marketing value by providing a comprehensive view of inherent benefits or potential concerns associated with chemical products; Clarifying expectations in the supply chain and Effectively managing issues of confidential business information (CBI) when multiple parties are involved in research and development chemistry.
A Novel Method to Optimize Horizontal Bakken Completions in a Factory Mode Development Program
Authors: Shelley Robert , Guliyev Nijat , Nejad Amir 
Published: October 2012

Abstract
This paper will describe a new method to facilitate optimization of hydraulically fractured horizontal Bakken completions. A key component of this method is a predictive data-driven model developed from a detailed evaluation of over 50 horizontal Bakken completions. Using this model, production predictions and economic optimization can be quickly performed using only data obtained during lateral drilling operations. This type of modeling and optimization of new horizontal completions fits well with a factory mode (rapid pace of well completion and hydraulic fracturing) of resource development.
The need to create large amounts of fracture area and the associated costs create an opportunity for economy of scale. Unfortunately, the time and expense required performing logging runs to gather data, and estimate reservoir and rock properties to facilitate completion design and optimization reduces operational efficiency and increases well cost. A data-driven approach to optimizing hydraulically fractured horizontal completions does not reduce operational efficiencies since it can be developed from common data and information obtained during drilling operations.
The data-driven model shows that reservoir quality, as one would expect, has the dominate effect on Bakken production. In addition hydraulic fracture design/methodology, fracture spacing, proppant selection, frac staging methods, frac compartment isolation, drillout/cleanup procedures, wellbore length and orientation have a significant effect on well production and economics. Several case histories will be included in which data-driven modeling was used to evaluate various completion/frac scenarios, predict production and facilitate completion/frac optimization.
The challenge of optimizing horizontal Bakken completion and frac design (30 or more hydraulic fracturing treatments per well) in a fast paced factory mode of resource development is problematic. The methodology described in this paper has been helpful to identify production drivers and facilitate well planning while also supporting a factory mode of resource development.
A New Family of Anionic Surfactants for EOR Applications
Authors: Gao Bo , Sharma Mukul M. 
Published: October 2012

Abstract
A new family of anionic surfactants that has great potential for EOR applications was synthesized and characterized in our lab. The unique and versatile structure of these surfactants has endowed them with properties that are attractive for enhanced oil recovery. A detailed experimental study was carried out and is presented here on the oil-water and solid-water interfacial properties of seven novel molecules.
The interfacial properties of this series of seven anionic surfactants with different length of hydrophobic tail and linking spacer group show systematic trends in interfacial tension and static adsorption density with changes in solution conditions. These molecules showed excellent aqueous stability even in high salinity and hard brines. Ultra-low IFT values were measured at low surfactant concentrations. The synthesized Gemini surfactants also showed lower maximum adsorption densities than the conventional single chain surfactants. The results from this study showed the potential of utilizing these surfactants at low concentrations and in harsh reservoir conditions.