bluuebunny/crossref_metadata_2025_split huggingface dataset:
Two Dimensional Monte-Carlo Simulation Method of Risk Assessment for Strategic Asset Investment Decision Making
Authors: LI D. , Chang P. , YANG X. , SUN Z. , JIN F. , YIN Y. 
Published: September 2015

Abstract
Because systematic and project specific risks exist during the project feasibility phase, the variability and uncertainty of these risks included in economic modeling improve the estimation of an assets NPV or IRR. For strategic investment decision making, parameters are defined with uncertainties and variability's. Examples of these type of parameters include raw material and product prices, Capital and Operating Expenses (CAPEX and OPEX), inflation index, interest and exchange rates. The purpose for gathering these data is to simulate the probability distributions of NPV or IRR using two-dimensional Monte Carlo Simulation. Sensitivity analysis, economic limit analysis and stress analysis are applied to optimize the final results for decision makers. This paper uses a case study to demonstrate the validity and effectiveness of a proposed method for project strategic investment decision making.
Testing a Heavy Oil Well in Ultra Deep Waters: Challenges Overcome by the State of Art Technology in Atlanta Project, Santos Basin, Brazil
Authors: Pedroso Carlos A. , Monteiro Gabriel Goes , Marsili Marcelo D. , Libório Fernando , Pessoa Rui , Farias Marcelo 
Published: September 2015

Abstract
Testing heavy oil in offshore wells is, by itself, a challenge. But testing heavy oil, highly viscous (220 cP at the reservoir temperature), in ultradeep waters (1550 m), in a horizontal well equipped with a long open hole horizontal gravel pack (800m), using an electrical submersible pump (ESP) deployed in a slant section at 75 degrees is really a big challenge.
Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001. The appraisal plan, started at the same year, included a deviated well to test the eocenic sandstones. A cased hole gravel pack was installed. The 90m interval tested, showed an unconsolidated sandstone, with high porosity (35%) and high permeability (5D). However, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), very acidic (TAN=9.8).
In 2006, a long horizontal well was drilled to validate the field development concept and evaluate the potential of this kind of well construction. However, crucial problems were faced in the drilling and completion phase, which included, directional control problems, massive fluid loss in the reservoir section, use of a LCM pill, premature screen during the open hole gravel pack operation, leaving a SAS completion. Even after these problems, it was decided to maintain the well test. An ESP was run in the DST string. After some flow (approximately 20 h), the screens were plugged resulting in their failure and therefore sand/solid production. The ESP locked with the produced solids and overheated, getting burned. The partially conclusive DST showed a severe damaged well, with high skin of 40. The well was abandoned without carrying out its objectives, and the horizontal completion was not fully evaluated.
The bad experience compromised the reliability of the project. However, in 2012, another operator decided to revisit the lower completion and testing procedures. After considering technology improvements and the lessons learned in the past operations, an extensive testing program was stablished and carefully executed. In 2013 a well was drilled, completed and successfully tested, with the ESP near the top of the reservoir. The zero skin completion and high productivity of the well encouraged the operator to drill and test the second well, this time using the ESP above the sea bed, inside the drilling riser, which included more difficulties due to the low temperature at that position.
This paper presents the main challenges and details on how they were overcome by the successful completion and testing of the first two production wells encouraging to move on to the next phase.
Assessing Field Development Plan for Green Fields Using an Integrated Asset Approach, an Angolan Case Study
Authors: Mora Jose Alberto , Khor Siew Hiang , Mason David , Nistor Mariana Laura , Willans Tim 
Published: September 2015

Abstract
Field development planning for an asset requires close interaction between different domains and departments, to reduce any potential uncertainties within the studied asset. Reducing uncertainties is crucial in investment preparation for a new green field development. By adopting an integrated asset approach, such cross-department interactions can be further improved by breaking down the barriers and assembling an integrated asset team with a common goal. This paper summarizes the construction of an integrated asset study for an offshore green field and compares the study against those obtained from the standalone-domain models. In this study, a reservoir simulation model was coupled to the wells and network models, which were further integrated to the processing facilities models and the asset economics evaluation model.
The aim of the study was to evaluate an existing field development plan (based on the traditional standalone approach) with an integrated asset approach to identify any possible constraints and potential deviations, enabling proactive actions to be taken on the asset management for future operations. The work presented here encompasses the use of various numerical simulation software applications working together in a single simulation environment, which allowed sensitivity analysis on different elements of the asset and evaluation of any possible impacts among the studied elements, such as manifold choke sizing and gas lifting parameters.
This assessment consists of a study from reservoir to economics, taking into account of wells, pipelines, surface equipment, production networks and downstream process facilities. The study demonstrated any components of the production network system and topside operating condition could impose constraints on the reservoir deliverability. Apart from evaluating various operating scenarios to best utilize the emerging capacity and to investigate back-out efforts and other challenges during the field development, it also provided guidance on how to further optimize the production system in terms of finding choke sizes over time and adjusting gas lift injection according to gas availability and operating pressure constraint. With its integrated asset approach, this study also presented a base case that could be extended with inclusion of gas lift distribution system to enable a more comprehensive analysis and asset field development study.
Using Data Analytics to Analyze Reservoir Databases
Authors: Lee Brian B. , Lake Larry W. 
Published: September 2015

Abstract
There are many public and private databases of oil field properties the analysis of which could lead to insights in several areas. Recent trend of Big Data has given rise to novel analytic methods to effectively handle multidimensional data, and to visualize them to discover new patterns. Using a commercial reservoir properties database, we created and tested four data analytic models to predict ultimate oil and gas recovery efficiencies, using the following methods borrowed from data analytics: linear regression, linear regression with feature selection, Bayesian network, and artificial neural network. The accuracy of result and robustness of each approach is presented and discussed.
New Electronics Ensure Increased Operational Efficiency in Highly Deviated, High Temperature Gas Well
Authors: Sagr Hani , Al-Sadoon Khalid 
Published: September 2015

Abstract
This paper describes a case story from Saudi Arabia where an extreme downhole environment required new developments in electric line intervention technology. This operation was the first time the new DC electronics package was used in the Middle East.
A major operator needed to test casing integrity and perform a perforation on a high pressure/high temperature well (310°F, 91° horizontal well). Standard wireline conveyance was not an option, pump down logging wasn’t available, and coiled tubing was too time consuming. New technology had to be considered. Multiple feasibility studies, including heat studies, were performed to verify that an e-line tractor equipped with newly developed DC electronics equipment would be able to execute the job under the extreme well conditions.
The job consisted of two runs; the first conveyed a cement bond log and a multi calliper imaging tool to 18,725 ft. while the second run conveyed a 3 3/8" gun to perforate the desired zone at 18,725 ft. The e-line tractor worked as planned despite the high temperatures and the 18,725 ft. extended reach section.
Using an e-line solution provided better data quality by having access to more advanced depth determination tools. Costs were reduced and the operational efficiency was increased by saving time. The environmental impact and risks were also reduced as the e-line solution eliminated mobilizing a rig.
Advanced Drilling Induced Fracture Modeling for Wellbore Integrity Prediction
Authors: Kostov Nikolay , Ning Jing , Gosavi Shekhar V. , Gupta Piyush , Kulkarni Kaustubh , Sanz Pablo 
Published: September 2015

Abstract
We present a method for modeling drilling induced fractures dynamic growth through a porous medium in the near wellbore region. Understanding the early time fracture growth behavior, and related near wellbore stress state, can provide an effective tool to improve the treatment selection through parameters such as particle size distribution and ideal drilling fluid rheology. Also, it will help with field diagnostics for various lost circulation treatments and lost return events.
ExxonMobil Upstream Research Company and SIMULIA® co-developed fully-coupled hydraulic fracturing modeling capabilities. The method is based on Cohesive Zone Modeling (CZM) elements, with pore pressure degrees of freedom, which were recently implemented into SIMULIA® Abaqus finite element package. The model was benchmarked with known solutions to analytical fracture growth regimes and validated with a laboratory scale experimental setup of hydraulic fracturing. The model allows for fluid leak-off from the wellbore and fracture faces into the porous medium, as well as an arbitrary injection schedule. Additionally, the physics of dynamic fracture growth and a variety of material properties and constitutive models for both the solid and liquid, are also captured in the model. The time-dependent fracture growth and interaction between the stress concentration region near the fracture tip and the wellbore result in a non-linear behavior of the near-wellbore stress state during early time fracture propagation, which was not possible to capture with static models. The model generation, execution, and post-processing are part of an automated workflow which requires minimal user time.
This analysis allows for recommendation of optimum fracture width for maximum increase in wellbore integrity in the target formation. This is done by selecting the fracture width at the mouth, at which a necessary increase in the near-wellbore tangential stresses has been achieved as to prevent initialization of further fractures.
Aluminum Alloy Enhanced Drill String Saves Over $500,000 by Increasing Small Rig Depth Capacity in Marcellus
Authors: Lehner Jeffry K. , Garcia Joe 
Published: September 2015

Abstract
An operator, seeking economies in constructing horizontal wells on pads, used a portable rig to air drill vertical holes and tangent sections to target depths of up to 8,000 ft TD, before using a larger rig to drill the curve and lateral well sections. With a 200,000 lb hookload rating, the portable rig had a depth capacity of approximately 6,000 ft using steel drill pipe (SDP). To increase the rig's depth capacity, the operator used up to 3,000 ft of aluminum alloy drill pipe (ADP) in a mixed SDP/ADP string, reducing weight and drag. Taking this approach, the operator has successfully achieved drilling objectives on 12 wells, for total savings of over $500,000 in spread cost.
Performance Evaluation of Automatically Generated Statistical Type Curves
Authors: Kuzma Heidi Anderson , Conradson Janette D. 
Published: September 2015

Abstract
Predicting the future production of Proved UnDeveloped (PUD) reserves is an important part of the evaluation of any asset. In the absence of production history, the most reliable way to make a PUD forecast is by analogy with production histories from similar nearby completions. This is most often done using a type curve. A traditional type curve is generated by normalizing to one the production histories of analogous wells and finding the shape of a curve which best fits their average decline. This is a tedious process when done by hand, and results are so difficult to test that in practice they rarely are. Our study introduces a methodology for testing statistical type curves based on 5-fold cross validation (5FXV), which rigorously evaluates the ability of an algorithm to produce accurate type curves, giving confidence that those type curves can be used to make careful and informed decisions. We offer two case studies to demonstrate the strength of the method and introduce a useful extension of the method.
A physio-statistical algorithm named BetaZi (BZ) automatically generates type curves which are considerably richer than a simple shape. They include information about actual production ranges abstracted as percentiles (90% of the time, actual production from a new well is expected to exceed the BZ p90 bound; 50% of the time it should exceed the p50, and so on.) 5-fold cross validation (5FXV) is used to test the performance of the algorithm. In 5FXV, a random 10% of the data from analogous wells is held out for testing and the remaining 90% is used to generate a type curve. A quantile-quantile (Q-Q) evaluation is made which compares the number of times the test data exceeded the bounds predicted by the type curve. The process is repeated 5 times on different subsets of data.
For this paper, we use 5FXV to estimate type curves for several plays in the Bakken and Kansas. The results show that excellent performance can be achieved if enough analogous wells are available to generate the type curve. Type curves that are made with wells that are not analogous can lead to overinflated estimations of value, as is shown with the Kansas wells. Finally, a p-score is computed for each well using the type curve, allowing production from wells of different histories to be conveniently plotted on one map or cross-plotted with other parameters.
Autonomous Marine Vehicle: A Cost Effective Technology to Manage Risk in Exploration and Production
Authors: Pai Sudhir 
Published: September 2015

Abstract
This abstract discusses the development of a multimission, autonomous sensor platform and describes applications ranging from measuring metocean parameters to detecting oil seeps in a cost effective manner with full Service Quality and HSE compliance. Examples from Gulf of Mexico and other offshore areas of the world demonstrate how persistent, unmanned mobile monitoring platforms have proved beneficial and effective to offshore exploration and production efforts, moving this technology from a state of infancy towards maturity.
Accurate meteorological and oceanographic data are essential for developing climate models and weather forecasts used in planning offshore exploration and production operations. A new remotely controlled, autonomous marine vehicle (AMV) supports a variety of sensors for conducting detailed metocean surveys across vast distances and under extreme conditions. To gather this data we use a wave powered AMV that harnesses kinetic energy from wave action to produce locomotion in the ocean, while remaining environmentally friendly and fuel-free; the vehicle is completely self-sustaining using solar panels to power its payloads. The platform includes navigational and control systems with communication to an operations center via satellite.
Once deployed the AMV uses no crew, requires no fuel and produces no emissions, thus eliminating both risk to personnel and impact on the environment. For less than the cost of a moored buoy or a vessel and crew, the vehicle provides mobility and long-range endurance for extended ocean monitoring missions. The propulsion system allows it to hold station in tidal or eddy currents. It simply steers to a designated waypoint—a programmed set of geographic coordinates. When it approaches the limits of a predefined watch circle, it turns around and heads back to the same point repeatedly. The AMV can maintain station for long durations with a watch circle of 25 to 50 m [82 to 164 ft], depending on currents and sea state. By contrast, the mooring systems of deep-ocean buoys employ ground tackle that produces a much wider watch circle the AMV can accommodate a broad range of off-the-shelf or custom sensors to fit the needs of the mission. A GPS receiver not only determines vehicle position, it provides a precise time stamp for all data recorded on the mission. Photovoltaic panels keep lithium-ion batteries charged to support WiFi, cellular or satellite communications systems, onboard data processing and various payloads.
This technology can and has assisted clients in providing early warning signs from a meteorological and oceanographic perspective for better managing risks and making critical decisions in protecting personnel and assets on installations both manned and unmanned. Value is enhanced when a number of these sensors are deployed on a swarm of vehicles to conduct pre-site baseline surveys for risk and insurance management.
Extra-Deep Azimuthal Resistivity for Enhanced Reservoir Navigation in a Complex Reservoir in the Barents Sea
Authors: Larsen David Selvåg , Hartmann Andreas , Luxey Pascal , Martakov Sergey , Skillings Jon , Tosi Gianbattista , Zappalorto Luigi 
Published: September 2015

Abstract
Goliat is an ENI Norge-operated oil field located in the Arctic Barents Sea, 85 km NW of the city Hammerfest (Fig. 1). The Goliat reservoirs have a complex structural setting characterized by a large number of faults and a relative high structural dip towards the flank of the structure. This challenging combination calls for horizontal production wells for effective drainage.
The Goliat field consists of several proven hydrocarbon reservoir units, but as of the date of this abstract, only Kobbe producers have been drilled. The Kobbe Formation is of Middle Triassic age and is divided into two main subgroups; the Upper Kobbe represents essentially a prograding deltaic system with mouth bars and tidal influenced lobes. In the Lower Kobbe, the system shifts into a more proximal, heterogeneous fluvial setting where sand bodies have limited lateral continuity.
One particular challenge is that the well design requires the 8½-in. reservoir section to be initiated in the overlaying Snadd shale. To minimize shale exposure in the landing section aggressive build-up rates are employed, decreasing the length needed in shale. However, a steep approach may lead to deeper penetration in upper Kobbe sandstone, which can result in unwanted intra-shale drilling. Therefore, the key to successful well placement is the early detection of the reservoir top and the accurate mapping of the reservoir sand architecture remote to the wellbore.
One way to successfully navigate a complex reservoir like Goliat is to use extra-deep azimuthal resistivity (EDAR) which can detect stratigraphic boundaries up 30m away from the wellbore in optimal resistivity environments (Hartmann, 2014). The development of advanced multi-component inversion modelling techniques (Sviridov, 2014) enhances the interpretations of resistivity data and can accurately provide real-time information regarding reservoir geometry.
On Goliat, the EDAR service provided the capability to detect the top of the reservoir at about 20 m true vertical depth (TVD) and nearly 100 m MD before entering the reservoir, enhancing accurate wellbore landing. Extra-deep measurements also helped reduced the uncertainty in fault detection, where related throw can be estimated based on the displacement of boundaries.
The use of a measurement with increased depth of detection (DOD), combined with advanced multi-component inversion while drilling techniques and real-time 3D visualization of data and reservoir model were vital to ensure the successful placement of the well. Real-time mapping of the reservoir geometry was key to optimize reservoir exposure.
The Effect of Reservoir Layering on Downhole Microdeformation Hydraulic Fracture Height Measurements
Authors: Sepehri Jay , Agarwal Karn , Davis Eric 
Published: September 2015

Abstract
The key strength of downhole microdeformation (i.e. tiltmeter measurements) is its ability to measure fracture height accurately by resolving the induced deformation pattern created by hydraulic fractures. The measurement provides additional insight into the actual hydraulic fracture height that might not be obtainable from microseismic data alone. The recent availability of combined downhole microseismic and microdeformation mapping in a single observation well has resulted in renewed interest in this technology.
Analysis of microdeformation data has typically been based on simple analytical models for fracture deformation in homogenous mediums, which might have limitations when rock layers with strong contrast in mechanical properties are present. This paper investigates the effects of layering on the deformation response induced by hydraulic fractures and the conditions under which using a homogenous model is justified.
A semi-analytic moduli perturbation method is used to calculate the deformation response caused by hydraulic fractures in a layered medium. The model can be used to estimate the deformation field attributed to finite rectangular dislocations up to the second order accuracy in a medium containing horizontal isotropic layers with different shear moduli. Effects of moduli contrast, distance of fracture tip to a layer interface, fracture crossing multiple layers, and tool spacing on estimation of fracture height and depth using downhole microdeformation are investigated.
Results indicate that, under most field conditions, the assumption of a homogenous medium is valid when inverting for fracture height using downhole microdeformation data. This is because the estimation of fracture height is dominated by the relative positioning of peaks in tilt response, rather than the absolute tilt magnitude, which can be affected by the elastic layer properties. Layering was observed to cause localized changes in tilt response near the layer interface without masking the overall fracture deformation response in most cases. The only scenario where layering was observed to have a significant effect on fracture height estimation was where fractures are contained within a relatively thick and uniform layer having strong contrasts in elastic properties from adjacent layers. Out of zone fracture growth into adjacent layers was observed to mitigate the impact of layering on the modeled tilt response, even in the presence of high moduli contrasts.