bluuebunny/crossref_metadata_2025_split huggingface dataset:
HSE Challenges in Thermal Operations Used for Heavy Oil Recovery
Authors: Qabazard Ahmed , Al-Qattan Ghadeer , Ketavarapu Sridhar Raju , Khan Nadeem Waris 
Published: December 2018

Abstract
Lower Faras Heavy Oil Project in Ratqa, North Kuwait of Kuwait Oil Company is one of the Major Projects in the upstream business in the Middle East. Heavy oil production from a large field is a significant challenge and involve process, which are not common for normally well-developed onshore upstream production operations personnel. There shall be a Limited/No Flow from a heavy oil well as the viscosity is high and to ensure extraction of hydrocarbon in a most possible efficient manner, thermal operations (including the steam injection) is the best option available. This additional process and associated equipment, their associated hazards are not available in the conventional oil & gas production.
Though the option of having a horizontal well with no additional steam/heat given to the reservoir, the flow from such wells can recover hydrocarbons, however it is not feasible for a commercial production. As a result, for commercial production, the reservoir is injected with steam (either cyclic or flooding) to recover the hydrocarbons in the most economical method. The steam injection method comes with a few challenges and the crux of success in Heavy oil production is to manage these hazards.
There have been several accidents that occurred worldwide in heavy oil production and related experimental activities. The root cause of accidents is generally the lack of awareness during the operation and maintenance activeness of the workforce personnel. Different incidents from world over, from the hazard identification and the operability studies undertaken during the project, suggest the various challenges that are underlying in the heavy oil operations. The challenges had been addressed systematically and design enhancement to enhance the robustness of the systems were considered whilst developing the project.
Optimization of Outflow Control Devices Placement and Design in SAGD Wells with Trajectory Excursions
Authors: Sidahmed Anas , Nouri Alireza , Kyanpour Mohammad , Nejadi Siavash , Fermaniuk Brent 
Published: December 2018

Abstract
Canada has enormous oil reserves which ranks third worldwide with proven oil reserves of 171 billion barrels. Alberta alone contributes with 165.4 billion barrels found in oil sands. However, the oil in oil sands is extremely viscous, and only 10% is recoverable through open-pit mining. In-situ thermal recovery methods such as Steam-Assisted Gravity Drainage (SAGD) have been developed and adopted as an efficient means to unlock the oil sands reserves.
Different reservoir geological settings and long horizontal wells impose limitations and operational challenges on the implementation of SAGD technology. Wellbore trajectory excursions or undulations- unintentionally generated trajectory deviations due to suboptimal drilling operations- are some of the complications that lead to non-uniform steam chamber conformance, high cumulative Steam-Oil Ratio (cSOR) and low bitumen recovery.
Conventional dual-string completion scheme (a short tubing landed at the heel, and a long tubing landed at the toe) has been widely adopted in most of the SAGD operations. Such configurations allow steam injection at two points: the toe and the heel sections of the horizontal well. However, these completions have demonstrated poor efficiency when reservoir/well complications exist. Tubing-deployed Flow Control Devices (FCD's) have been introduced to offer high flexibility in delivering specific amounts of steam to designated areas (such as low permeability zones) and ensure uniform development of steam chamber in the reservoir. The work in this thesis presents the results of a numerical effort for optimizing the design of Outflow Control Devices (OCD's) in SAGD wells for different scenarios of well pair trajectory excursions.
A coupled wellbore-reservoir SAGD simulation model was constructed to optimize the placement and number of ports in every single OCD. Three different cases were generated from the constructed basic SAGD model with each case having a specific well pair trajectory which causes variable lateral distances between the well pair.
Results of the optimized OCD's cases demonstrate a higher SAGD efficiency compared to their corresponding conventional dual-string cases. Those enhancements resulted in a higher steam chamber conformance, a higher cumulative oil production, and an improved Net Present Value (NPV).
Study on Radio Frequency Heating Pattern of Heavy Oil Reservoir Based on Multi-Antenna Configuration
Authors: Wang Zhengxu , Gao Deli , Liu Kui , Tan Teichuan , Wang Zhiyue , Li Wenlong 
Published: December 2018

Abstract
Compared with other electrical heating processes, RF heating has the advantages of volumetric heating, therefore it has great development potential in extracting heavy oil resources. Because the EM waves used to heat reservoir are mainly derived from RF antennas, it is necessary to determine the multi-antennas layout in the horizontal wellbore to maximize the thermal energy dissipation in a single reservoir layer with uneven thickness, and minimize the extra heat loss in non-reservoir.
In this work, the combination of three antenna arrays is considered during RF heating process, and the effects of their distance and operating parameters (voltage, and frequency) on heating patterns are analyzed. In addition, in order to achieve the purpose of heating reservoir at the expense of the least amount of electrical energy, the heating efficiencies of the antenna arrays with equal and different spacing are compared. At last the mathematical model used to describe RF heating process is solved by COMSOL to obtain the reservoir temperature profiles.
Simulation results indicates that the frequency and voltage applied to each dipole antenna have a contribution to the heating pattern, including heating range and direction. With the increasing antenna array spacing, the heating range expands, but the maximum reservoir temperature declines. In addition, the temperature distributions in the perpendicular bisectors of any two adjacent antennas trend to gradually diminish with the increasing spacing. Gradually increasing antenna spacing will also weaken the temperature accumulation effect at the center of the reservoir. When the single reservoir layer with different thicknesses is heated, the maximum heating efficiency is 0.73 in the condition of the antenna configuration with the same spacing. Whereas, the efficiency is up to 0.88 if the optimized spacing is adopted. Results indicate that the heating mode can be governed by optimizing the heating distance, as well as selecting the appropriate operating parameters.
The determination of RF heating pattern can provide the solutions for the placement of multiple antennas in horizontal boreholes. Ultimately, the extra energy waste is avoided and the maximum heating efficiency is accomplished.
The Role of Big Data Analytics in Exploration and Production: A Review of Benefits and Applications
Authors: Noshi Christine I. , Assem Ahmed I. , Schubert Jerome J. 
Published: December 2018

Abstract
Due to the decrease in commodity prices in a constantly dynamic environment, there has been a constant urge to maximize benefits and attain value from limited resources. Traditional empirical and numerical simulation techniques have failed to provide comprehensive optimized solutions in little time. Coupled with the immense volumes of data generated on a daily basis, a solution to tackle industry challenges became imminent. Various expert opinion fraught with bias has posed extra challenges to obtain timely cost-effective solutions. Data Analytics has provided substantial contributions in several sectors. However, its value has not been captured in the Oil and Gas industry.
This paper presents a review of various Machine Learning applications in exploration, completions, production operations to date. An overview of data-driven workflows in the fields of electric submersible pump (ESP) failure and shutdown prediction, reservoir databases’ analysis, reduction of subsurface uncertainty, EOR decisions using scarce data, improved oil recovery estimation, production impact assessment, horizontal completion, fracturing techniques, production optimization in unconventional reservoirs, production management, and field surveillance, is presented.
The review attempts to shed light on the benefits and applications of multiple challenges faced on a daily basis by scientists, field personnel, and engineers to help solve and optimize the industry's multi-faceted data-intense challenges.
In Situ Heavy Oil Upgrading by Electric Enhanced Oil Recovery, Complex Carbonate Heavy Oil Field Case
Authors: Keglevic Kresimir 
Published: December 2018

Abstract
This paper describes novel electrochemistry based in situ heavy crude oil upgrading technology and also field case and results of In Situ Oil Upgrading from Visoke Heavy Oil Field, Albania, produced oil changing chemical composition results, as well as gains in crude oil production and reducing water cut.
EOR technologies such as various thermal methods, CO2 flooding and chemical floods have gained increased interest due to the decreasing number of new-field discoveries, increasing number of maturing fields and higher oil price.
Among the emerging EOR technologies, electro chemical Electric Enhanced Oil Recovery is the new generation of tertiary oil recovery enhanced by electro kinetics (electro osmosis) and electro chemistry.
By tailored application of direct current on hydrocarbon reservoir between two wells, which serve as anode (+) and cathode (-), usually several fold oil production increase is achieved at cathode well, while production at anode well, if production well serves as anode, stays as before or slightly increased.
Method, if anode and cathode wells are cased and perforated, does not require any work over for field application, just connecting control panel with power source (3 phase 380 V, 18 A, 50 or 60 Hz) and electrically connecting control panel with well heads (casing or tubing) which previously should be electrically insulated by insertion of resistive tube in production line.
Application of Data Analytics to Improve Drilling Performance and Manage Drill Stem Vibrations
Authors: Al Dushaishi Mohammed , Hellvik Svein , Aladasani Ahmad , Alsaba Mortadha , Okasha Qutaiba 
Published: December 2018

Abstract
Data mining and Artificial Intelligence (AI) methodologies are underdeveloped in the oil and gas industry, despite the need to improve drilling performance and remain globally competitive in all capital-intensive projects.
Drilling companies allocate significant resources to improve well planning, drilling schedules and rig management. Well planning comprises of two main elements; drilling performance and the reduction of drill stem vibrations. Therefore, modeling methodologies such as drill string statics, dynamic tools and rate of penetration modeling are applied to determine the optimum bottom hole assembly (BHA) components and drill bit design. However, more attention is required on drill stem fatigue, non-productive time (NPT) and their impacts on drilling operations.
In this paper, Data Analytics (DA) is applied to drilling logs taken from three wells that recorded vibration readings from different geological stratification. In turn, the work in this paper establishes a relationship between drill stem vibrations and various measurement and logging data while drilling. Statistical regression and multivariate analysis were used to examine correlations of drilling parameters, including BHA assembly, to vibration data. Therefore, the results include a composite vibration model that describes the drilling stem vibration behavior as a function of drilling parameters, and geological formations.
Results of the vibration models built in this study indicate that the drill stem lateral vibration behaves parabolically as a function of the drill pipe length, length of drill collar, gamma ray (GR) response, and weight on bit (WOB). The analysis of drill stem vibration effect on the mechanical specific energy (MSE) was inconclusive for depths below 1350 meters. However, for depths above 1350 meters a strong correlation was observed to ROP.
Enhancing Safety Culture through Changing the Mindset : Business Partners' HSE Performance: Practical Evaluation, Benchmarking & Path to Improvement
Authors: Al-Qallaf Yousef , Al-Azmi Abdulla , Adivi Bala Siva , Al-Harbi Musaed , Devaraj Christopher 
Published: December 2018

Abstract
Achieving excellent HSE performance is one of the main objectives of any industry, especially by High Hazard or Major Accident Hazardous (MAH) industries. Considering various national and global market demands, Oil & Gas industry must be ready to embark on challenging scenarios. To ensure such challenges are successfully addressed, the role of business partners (Business Partners) is very much vital and important as many projects are to be executed to achieve the set objects/targets safely.
In many organizations, HSE (Health, Safety and Environment) or HSSE (Health, Safety, Security and Environment) has been considered as one of the strategic objectives. In order to achieve such objectives, moving together with Business Partners (Contractors) bring lot of importance. In addition, this makes organizations to uphold a safe work environment at the work sites that demands and expects collaboration and support from the Business Partners who are on board as well as who will be on board with the respective organizations.
Considering the dynamic challenges, achieving and sustaining excellent HSE performance is very essential, specifically in High or Major Accident Hazardous (MAH) industries such as Oil & Gas. Such industry who is having Business Partners from various countries, having multi-nationals as work force gives challenge to ensure Organization's HSE expectations are understood and implemented.
Thru-Tubing Conveyed Rigless ESP Technology: A 20-Year Case History of Wireline Retrievable ESPs.
Authors: Patterson John , Dornan Grant , Targac Gary , Malone David , Cheblak Samer , Julian Jennifer , Walker Matthew 
Published: December 2018

Abstract
Electrical submersible pump (ESP) technology is a proven artificial lift method for shallow, low pressure reservoirs like those found in the West Sak viscous oil field in Alaska. However, the unconsolidated nature of the West Sak sands challenges the long-term lifting performance and reliability of conventional ESP systems due to sand production. This challenging environment causes ESP pump erosion and accumulation of sand in the tubing above the pump and in the lower completion below the ESP.
This paper presents a 20-year case study of the of the world’s largest, longest-running population of thru-tubing conveyed (rigless) electric submersible pumps. Conventional ESP’s require a rig to replace a pump or motor when either fails. In "rigless" systems, some of the components (pump only for Generation 1, and pump, seal, and motor for Generation 2) can be pulled and replaced using slickline (SL), coiled tubing (CT), or tractor, depending on wellbore deviation. Generation 2 systems consist of a downhole side pocket mandrel (or docking station) with a wet-connect attached to the electric cable and deployed on 4-1/2" or larger tubing. Not only do these systems allow both the pump, seal, and motor to be retrieved without a rig, they have the significant advantage of allowing 3.80" fullbore access below the pump setting depth without pulling tubing. This allows non-rig interventions such as reperforating, production profiles, CT cleanouts, CT drilling etc. to be performed after the pump, seal, and motor are pulled with conventional SL or CT. Once the desired intervention has been completed, the pump, seal, and motor can be redeployed with SL — wet-connecting to the downhole side pocket mandrel. A well with a conventional ESP would require pulling the tubing with a rig prior to and reinstalling the tubing following any well intervention below the pump setting depth. "Rigless" technology has significantly increased production uptime and reduced the cost of ESP interventions in these wells.
The case study includes the analysis of the two generations of rigless ESP systems, quantifying the success rate in varying conditions in over 300 rigless ESP replacements in a high sand, high deviation environment on Alaska’s North Slope.
Evaluating the Performance of CO2 Foam and CO2 Polymer Enhanced Foam for Heavy Oil Recovery: Laboratory Experiments in Unconsolidated and Consolidated Porous Media
Authors: Telmadarreie Ali , Trivedi Japan J 
Published: December 2018

Abstract
Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. The higher viscosity of oil in such reservoirs, add more challenges and severe the difficulties during any EOR method (i.e. high mobility ratio, inadequate sweep, reservoir heterogeneity) compared to that of EOR from light oil reservoirs. Foam has gained interest as one of the EOR methods especially for challenging and heterogeneous reservoirs containing light oil. However, the foam and especially polymer enhanced foam (PEF) potential for heavy oil recovery is less studied.
The current study aims to evaluate the performance of CO2 foam and CO2 PEF during heavy oil recovery from both unconsolidated (i.e. sandpack) and consolidate (rock sample) porous media with the help of fluid flow experiments. The injection pressure profile, oil recovery, and CO2 gas production were monitored and recorded to analyze and compare the performance of CO2 foam and PEF for heavy oil recovery. A visual sandpack made of glass column and a core-flood system capable of measuring the pressure at different sections of the core were used in this study. Homogenous and fractured sandstone core samples, as well as a fractured carbonate core sample, were selected for the core-flood study.
Static stability results revealed slower liquid drainage and collapse rates for PEF compared to that of foam even in the presence of heavy crude oil. The addition of polymer significantly improved the performance of CO2 foam flooding during heavy oil recovery in dynamic experiments. This result was inferred from faster propagation rate, higher dynamic stability, and higher oil recovery of CO2 PEF over CO2 foam injection. Moreover, the visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to the conventional foam flooding. In the fractured porous media, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion inferred from pressure profile and gas production data.
The results obtained from this study show that CO2 PEF could significantly improve the heavy oil recovery and CO2 sequestration, especially in homogeneous porous media.
Balancing Sub-Surface Needs, Surface Planning and Reduction in Operational Cost for Placement of Observation Wells in a Kuwait Heavy Oil Field
Authors: Benham Philip , Zhang Ian , Freeman Mike , Choudhary Pradeep , Montero Jacobo , Spring Laurent , Warrlich Georg , Shen Chonghui , Ahmad Khalid , Ren Zubiao , Al-Dohaeim Khalid , Al-Rabah Abdullah 
Published: December 2018

Abstract
As KOC prepares for production ramp up in a North Kuwait Heavy Oil field, one key for cost efficient development is in optimizing information from observation wells. Given multiple objectives for data collection and restrictions due to dense well spacing and surface infrastructure, it is critical to apply an efficient methodology for the selection of observation well locations. This paper describes the interplay between subsurface needs and urban planning in decisions for placement of observation wells to reduce operational costs, enforce effective field development planning and ensure robust production levels.
The observation well location selection protocol in a heavy-oil steam development requires initial focus on identifying the key subsurface parameters and risks including cap-rock integrity, role of baffles in steam conformance, gas caps, aquifer influx as well as development decisions like adequate well spacing to apply micro-seismic, e.g. Key parameters were mapped and rated with a "traffic-light" approach to distill the diverse datasets into manageable form. Next, different observation well location strategies (evenly distributed, clustered and blended) were assessed and locations (driven by subsurface objectives) were chosen. Finally these locations were reconciled against the surface restrictions, HSSE and operational constraints to determine the final program.
A successful observation well strategy will have:
– Good subsurface models capturing heterogeneities in order to predict production performance – Sufficient well number and thorough reservoir architecture characterization underpinning well placement – Robust data collection plan (including production data) – Proper staff resources applied to monitor and QC the data – Up-to-date and accessible data-base, that can be interactively interrogated – Cross-discipline integration, regular data reviews and alignment with urban planning
The inherent value in observation wells is optimized by defining key objectives with broad across discipline engagement, aligning data collection objectives and engaging urban planning and field development with sufficient lead time. This collaborative approach reduces costs for KOC by avoiding rework, missed data collection opportunities or missed value adds if options such as conversion of observers to producers are not considered.
Process Safety Management Challenges in Heavy Oil Production
Authors: Ketavarapu Sridhar Raju , Sawlikar Vishal , Qabazard Ahmad 
Published: December 2018

Abstract
The complexity of the production from Heavy Oil Field increases many folds during the lifecycle of the field. The inclusion of Process Safety Management (PSM) from concepts of the project adds value; however, the uncertainty can be very canny as the parameters keep varying over each production cycle.
A large field development and the operation during the lifecycle should be harmonious; it is supported by PSM and Barrier Management which plays a vital role in preparing and guiding towards a holistic Risk Management.
Technical Safety Studies can be challenging as scenarios keep changing on every production cycles and each of the uncertainty has to be compounded with different iterative simulations. They shall as minimum include H2S, Thermal expansions and possible thermal releases, corrosion rates, flow parameters and monitoring.
The challenges has been addressed based on KOC's understanding of the risk, the Pilot Project experience. The significant barriers and process safety challenges had been incorporated during the engineering stages of the large field production design. A set of barriers has been identified to ensure a smooth operation during the entire life cycle.
The Heavy Oil Operations is yet to commence but the simulated model has been showing a satisfactory result considering the Accidents, lessons learnt from incidents world over, brainstorming from Industry experts and consultants from all relevant domains.
The study has resulted in the identifying the various process and non-process (including human factor aspects).
These barriers identified and its impact shall benefit in creating a basket of barriers to easily choose on a similar project. Further the studies concluded resulted in barrier of mitigation and controls incorporated in the project and highlighted in the operational manuals
The novelty of the understanding of the Challenges, risk management, Barriers Controls and Mitigation by creating a Basket of Issues that can be included in complex Heavy Oil Operations project by ensuring large coverage of Process Safety Activity.