bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successfully Completing and Producing a Deepwater Gulf of Mexico Well With No Cement Behind Pipe
Authors: Hopper Tim S. , McCutcheon Joseph B. , Shaposhnikov Pavel 
Published: October 2017

Abstract
Noble Energy, Inc. successfully drilled a deepwater exploration Middle Miocene well in November 2012 and discovered the Big Bend Field, located in the Gulf of Mexico Mississippi Canyon Block 698. As the production liner was being run in the MC 698 No. 1 discovery well, tight hole conditions were encountered near total depth. While pumping the primary cement job, lost returns were observed. Prior to the drilling rig leaving location, a cement bond log was run to evaluate the primary cement job. There was no evidence of cement bond across the main oil-bearing zone or directly above it. This was a concern since there are water sands above the main oil-bearing zone which could compromise future production with behind pipe communication issues, in addition to potentially complicating the completion. Plans were made to pump squeeze cement to remediate the primary cement job. When the rig returned to complete the well, a second cement bond log was run February 2014 and compared to the original cement bond log. The second cement bond log showed a zone of sufficient bonding above the main oil-bearing zone, where no bonding was evident on the previous bond log. There was still no evidence of cement across the main oil-bearing sand. Even though preparations were made to remedial squeeze the primary cement job, the decision was made to not engage in remedial cement operations and to continue with the completion. This paper compares the two cement bond logs and discusses the operational considerations leading to the successful completion of the well and producing a prolific oil well safely with no water production.
Applying Data Management and Visualization to OPEX Reduction and Improved Asset Integrity Programs
Authors: Arciero B. V. , Ismail H. 
Published: October 2017

Abstract
The Digital Oil Field (DOF) has been exhaustively discussed for production enhancement and optimization, but there has been little focus on its use in other areas. This paper describes an integrated approach by multiple business units on how data management and visualization is been applied to enhance decision making, improve cost control, and increase asset integrity in Murphy’s onshore and offshore developments.
Data visualization and the automation of data reporting play an important role in achieving the goal of reducing OPEX and optimizing field operation activities. As more data becomes available, a tool for maximizing the benefits of how data is presented and used in day-to-day decision making is required. This begins with reducing man-hours associated with data acquisition, report-generation, analytical tool development and key performance indicator (KPI) tracking. A data management and visualization tool is currently in-use to enhance offshore operations in chemical management, cost-tracking, and production forecasting, as well as unconventional onshore operations for asset integrity monitoring systems.
Since implementation, the program minimizes duplicate work by field personnel, as well as ensures they are engaged and involved in OPEX reduction and increasing field uptime. Effective visualization of data streamlines decision-making on chemical performance, cost-benefit analysis, and effective treatment. It also maximizes the amount of data available for use and interpretation.
In remote areas onshore field data is entered via mobile devices, providing a fast, simple, and effective tool for managing onshore maintenance campaigns, pigging programs, cathodic protection, & vessel inspections. New workflows provide real-time data and metrics to help make on the fly ‘fit-for-purpose’ decisions. Utilization of apps and dashboards has drastically changed the performance of the asset integrity & maintenance programs and significantly reduced OPEX across onshore and offshore assets, and improves reliability across pipeline and gathering systems by identifying high-risk areas and reducing system upsets.
This shift has moved focus from effective data collection to using the existing data in an efficient and cost-effective way in helping the operations engineering team and field operations in data analysis, KPI-tracking and achieving production and OPEX targets. It also provides indication of existing data gaps and identifies where more data collection would add value to business decisions.
Creating Value by Implementing an Integrated Production Surveillance and Optimization System – An Operator's Perspective
Authors: Sankaran Sathish , Wright David , Gamblin Huan , Kumar Dhilip 
Published: October 2017

Abstract
As operations extend to deeper and more complex reservoirs, the industry is faced with challenges towards efficiently appraising and developing these fields. Some of the key operational challenges include predicting, identifying and mitigating reservoir and well performance issues under uncertainty. Exacerbating this is the issue of volatile oil prices, manpower, staff rotations, increasing volumes of telemetry data handled by asset personnel and complex designs. Engineers often respond to this challenge by reacting to the situation and developing personal tools (spreadsheets) that are often not scalable at the corporate level.
Further, the classical silos of analytical tools are not always able to characterize and pinpoint the cause of any performance degradation. In these situations, there is a need to get a holistic understanding of the well and reservoir behavior by employing various engineering tools and develop effective remediation strategies. This understanding and early remediation leads to maximizing the value of the asset investments through better and prompt decision-making and collaboration.
This paper describes some of the technical challenges faced in deepwater operations and the methodology adopted for implementing an integrated production surveillance and optimization (IPSO) system to mitigate the risks. The IPSO (deepwater digital oilfield) system is designed to be a culmination of emerging information and communications technologies, intelligent algorithms and fit-for-purpose asset management workflows. Case studies are presented highlighting the benefits from implementing the IPSO system across all deepwater assets, including improved well and facility uptime resulting in increased efficiency and reliability, automating data gathering, early understanding of reservoir behavior and better overall performance. In addition, best practices and lessons learned from this deployment in a green field environment were applied to other mature brown field operations within the company.
Density Changes and Reservoir Compaction from In-situ Calibrated 4D Gravity and Subsidence Measured at the Seafloor
Authors: Agersborg R. , Hille L. T. , Lien M. , Lindgård J. E. , Ruiz H. , Vatshelle M. 
Published: October 2017

Abstract
Managing offshore hydrocarbon fields involves costly investments like drilling infill wells or installing compression facilities. A good understanding of the dynamical behavior of the reservoir is required for derisking such decisions. Time-lapse seismic is a suitable monitoring technology, but it involves large operational costs. On the Norwegian continental shelf (NCS), another geophysical method has been in use for two decades: 4D gravity and subsidence surveys, with a cost typically 15% of that of seismic surveys. Field cases show that, in some cases, this technology provides information beyond the reach of seismic within the required timeliness.
Time-lapse gravity changes at the seafloor are sensitive to changes in mass within the reservoir. As an example, vertical movements of water-gas contacts smaller than a meter can be detected under some circumstances by studying this observable (Ruiz et al., 2015). That is possible because of the high accuracy of the time-lapse gravity measurements, which is at the level of a few μGal.
Seafloor subsidence monitoring uses water pressure measurements at the seafloor as a starting point. Once the required tide corrections are applied, the method reaches accuracies of down to 2 mm, depending on the field conditions. This is much better than the accuracy specified by pressure sensor manufacturers, which amounts to typically 10 cm of water for a sensor qualified for 1000 m of water (Ruiz et al., 2016b).
New Method to Reduce Residual Oil Saturation by Polymer Flooding
Authors: Erincik Mehmet Z. , Qi Pengpeng , Balhoff Matthew T. , Pope Gary A. 
Published: October 2017

Abstract
Six coreflood experiments were conducted to investigate the effect of hydrolyzed polyacrylamide (HPAM) polymer solutions on the residual oil saturation in Bentheimer sandstone cores. All six cores were first saturated with brine and then flooded in the following sequence: oil to zero water cut, brine to zero oil cut, glycerin solution to zero oil cut, polymer in low-salinity brine to zero oil cut and finally polymer in high-salinity brine to zero oil cut. The first polymer solution had about the same viscosity as the glycerin solution. The first polymer flood was designed to maximize the effect of viscoelasticity on the residual oil saturation by flooding the cores at a high Deborah number, and as expected resulted in a lower residual oil saturation. The second polymer flood in high-salinity brine had about the same viscosity, but a much lower relaxation time and the flood had a much lower Deborah number. Unexpectedly, there was a further substantial reduction in residual oil saturation during the second polymer flood. The lowest residual oil saturation after the second polymer flood was only 0.07. This is a truly remarkable result considering there was no reduction in interfacial tension, the capillary numbers were maintained below the critical capillary number for Bentheimer sandstone, and the viscosities of both polymer solutions were equal to or less than the glycerin solution.
A Study of Connectivity and Baffles in a Deepwater Gulf of Mexico Reservoir Linking Downhole Fluid Analysis and Geophysics
Authors: Chen Li , Forsythe Jerimiah C. , Wilkinson Tim , Winkelman Ben , Meyer John , Canas Jesus A. , Xu Weixin , Zuo Julian Y. , Betancourt Soraya S. , Shan Dan , Hayden Ron S. , Gendur Jason , Hearn Richard , Kumar Anish , Lake Patrick , Mullins Oliver C. 
Published: October 2017

Abstract
Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deepwater. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of advanced DFA (Downhole Fluid Analysis), formation sampling and pressure measurements, borehole imaging and petrophysics. Reservoir fluid geodynamic analysis of Wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle. Geodynamic analysis of reservoir architecture employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment; nevertheless, the DFA-measured asphaltene gradients are shown to be superior to all other fluid measurements to determine reservoir architecture. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust geologic models populated with the accurate fluid structures of the reservoir. History matching months of production match most probable reservoir realizations which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.
Proposed Refracturing Methodology in the Haynesville Shale
Authors: Xu Tao , Lindsay Garrett , Baihly Jason , Ejofodomi Efe , Malpani Raj , Shan Dan 
Published: October 2017

Abstract
During the downturn in the oil and gas industry, many operators have chosen to refracture their previously underperforming wells to boost economics with lower investment compared to drilling new wells. More than 100 horizontal wells have been refractured using chemical diverters across multiple basins in North America since the second half of 2013. Many papers have been published discussing these case studies. However, the refracturing results have been inconsistent. One of the biggest challenges of refracturing with chemical diverters is not knowing what is actually happening down hole. To better understand what is happening, more refracture modeling should be performed to more reliably predict production results before spending the upfront capital for a refracturing treatment.
A proposed refracture numerical simulation methodology was employed to take into account the historical production depletion using calculated pressure and stress measurements along the lateral and in the reservoir. The altered stress fields resulting from reservoir depletion are calculated through a comprehensive workflow coupling simulated 3D reservoir pressure with a geomechanical finite-element model (FEM) described in a previous published paper. After the stress and pressure are updated, the new approach outlined in this paper is validated by production history matching real data from a previously refractured well in the Haynesville basin to provide more confidence in the end results. The main uncertainty in the process is how much of the lateral was stimulated. This paper also provides a sensitivity example to show how the model can be altered to predict different lateral coverage percentages.
Refracture modeling still poses a major challenge for engineers because of the reservoir complexity and uncertainty downhole while refracturing (i.e. reservoir heterogeneity, isolation efficiency, etc.). However, this proposed refracturing approach provides a basic guideline on how to model refracturing treatments in a numerical simulator with the help of altered stress fields caused by reservoir depletion. This can be used to better understand why previously refractured wells perform the way they do and to better predict the performance of future refractured wells.
Evolving Completion Technologies Mitigate Proppant Flowback
Authors: Swain C. , Powell J. , Stadnyk S. 
Published: October 2017

Abstract
The concept of "cutting costs at any cost" leads to poor short-term focused decisions which can result in higher total costs in the future. In many instances, any dollars saved in the initial completion are more than offset by costs incurred later in the life of the well. One such example is the operational difficulty and costs incurred in dealing with proppant flowback after fracturing operations are completed. In many such cases, a post-fracture cleanout is required before turning the well over to production, and subsequent additional cleanouts can be required after three to six months of production. This paper will examine the application of a completion methodology which has proven to minimize the inflow of proppant during both the fracture treatment, and during subsequent production. With minimal additional costs associated with the use of the method, the savings result in a benefit to profitability and capital preservation.
Investigating the Performance of Paraffin Inhibitors under Different Operating Conditions
Authors: Dubey Anshul , Chi Yuandao , Daraboina Nagu 
Published: October 2017

Abstract
Mitigating paraffin deposition in production lines has remained a critical issue for the oil industry to control the associated production and transportation cost. Recently, injection of paraffin inhibitors in the transportation pipelines has been widely used along with other strategies to improve production. This study investigates the effect of operating temperatures and geometries on the performance of paraffin inhibitors. Moreover, the experimental temperature differences (i.e. changes in coolant temperature and bulk oil temperature) strongly influence the inhibitor efficacy indicating that these conditions must be optimized prior to field applications.
The experiments were conducted with a Caspian Sea (CS) condensate at different temperature conditions using two paraffin inhibitors (Maleic anhydride co-polymers: PI-B and PI-C, where PI-B has a higher carbon chain length than PI-C). The inhibitor concentration of 500PPM and a 24h time duration is maintained for all the experiments. The deposit mass and wax content were analyzed.
Wax mass flux increases with the increasing temperature difference in constant bulk oil temperature experiments. In contrast, the mass flux increases first and then decreases with the decrease in the temperature difference in constant coolant temperature experiments. Hence, it is important to consider the influence of operating conditions that may change the oil properties significantly and ultimately the magnitude of the paraffin deposition. Deposit mass (decreased) and wax content (increased) are significantly influenced by the presence of inhibitors. The inhibitor efficacy, that incorporates both deposit mass and wax content, is calculated at different operating temperature differences. It has been observed that the efficacy strongly varies with the operating region. Hence, it is necessary to select proper inhibitors based on the local operating temperature conditions during injection.
This study provides a fundamental understanding between operating parameters and inhibitor efficacy. The usage of inhibitors is highly complicated and the knowledge obtained through this investigation disseminates crucial information on selecting proper inhibitor for field applications.
Automatic Flare Stack Monitoring
Authors: Janssen R. , Sepasian N. 
Published: October 2017

Abstract
Flare stacks must be continuously monitored to assure ignition of released gases during the plant operation. The process of flare detection is generally referring to detecting the presence or absence of a flare. Flare monitoring adds the capability of tracking the size of the flare to this process. By setting lower and upper monitoring boundaries an alarm can be generated if the flare becomes too small or too big. Reliable flare stack monitoring becomes significantly crucial to ensure no unburned toxic or waste gas is released into the atmosphere causing environmental issues and possible fire hazards. It also gives the operator an extra handle to optimize the production process. In this paper, we introduce an automatic flare detection and monitoring system. Our user-friendly system is computer vision based, plug-and-play and designed as a built-in part of the camera. Taking advantage of the geometrical properties of the flare as well as temporal information obtained by video analytics, we create a monitoring system robust to various parameters such as wind direction. Based on our knowledge, we are the first to present an automatic flare stack monitoring system with flare size tracking and automatic event signaling. Our presented system has been tested for live monitoring in the Rotterdam Botlek area, The Netherlands. The preliminary results illustrate a reliable system which is free of false alarms.
An Experimental and Modeling Study of Solvent-Bitumen Phase Behavior at Elevated Temperatures Using Cold Lake Bitumen
Authors: Eghbali Sara , Dehghanpour Hassan 
Published: October 2017

Abstract
Co-injection of CO2 or light hydrocarbons with steam in SAGD (Steam Assisted Gravity Drainage) process may enhance bitumen mobility and reduce Steam Oil Ratio (SOR). Understanding and modeling the phase behavior of solvent-bitumen system are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen-CO2 and bitumen-C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater formation. Constant composition expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2-bitumen mixture, and C4-bitumen mixture. The Peng-Robinson equation of state (PR-EOS) is calibrated based on the measured data and used for PVT modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 120 °C to180 °C. Further to that, dead oil viscosity measurements are conducted at similar temperature intervals to estimate oleic phase viscosity.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than CO2 at reservoir pressure of 580 psia (4,000 kpa) and temperature range of 120 °C to 180 °C. During the CCE tests, co-existence of three equilibrium phases is observed for the C4-bitumen system with 84 wt.% C4. The three phases consist of a solvent-lean (bitumen-rich) oleic phase (L1), gaseous phase (V) and a solvent-rich (bitumen-lean) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into L2 phase and preserve the heavy components in L1 phase. It is observed that the color of L2 phase becomes lighter by decreasing the pressure which may suggest extraction of lighter hydrocarbon components at lower pressures. Similar tests on the CO2-bitumen system only shows two effective phases over a similar temperature range. The two phases consist of a solvent-lean (bitumen-rich) oleic phase (L1) and a gaseous phase (V).
By using the regressed EOS model, phase equilibrium regions are predicted in the compositional space for the solvent-bitumen system. EOS predictions indicate two types of two-phase regions in composition space for C4-bitumen system (i.e., L1-L2 in temperature range of 120 °C to 148 °C and L1-V in temperature range of 148 °C to180 °C). However, only one type of two-phase region (i.e., L1-V) exists in the similar temperature range for CO2-bitumen system. The EOS predictions show that 1.7 wt.% CO2 can reduce bitumen viscosity by up to 4 times, and 8.7 wt.% C4 can reduce bitumen viscosity by up to 32 times in temperature range of 120 °C to 180 °C.
A Rigorous Solution to the Problem of Phase Behavior in Unconventional Formations with High Capillary Pressure
Authors: Neshat Sajjad S. , Okuno Ryosuke , Pope Gary A. 
Published: October 2017

Abstract
Phase behavior of hydrocarbon mixtures is affected by the petrophysical properties of the formation. This paper integrates several important thermodynamic and petrophysical aspects of the problem in a rigorous way, and introduces a solution that can be applied over the range of pore sizes in tight and shale formations in which hydrocarbons can be practically recovered. A new criterion for phase stability analysis is introduced that results in discovery of a new range of solutions for the capillary equilibrium problem. A novel three-phase capillary pressure model has been used to estimate the effect of connate water on the gas-oil capillary pressure. The model is then used in conjunction with the new stability method to solve several phase behavior problems for binary and multi-component reservoir fluids. We show that the new approach can significantly improve the estimation of phase behavior at high capillary pressure.