bluuebunny/crossref_metadata_2025_split huggingface dataset:
Roadmap to Unlock Light, Tight and Highly Laminated Oil Resources in South Oman
Authors: Al Hadhrami Abdullah , Al Riyami Abdullah , Schulz Ralf , Moiseenkov Alexey , Khayrutdinov Fanis , Smirnov Dmitrii , Al Kindi Nawal 
Published: November 2018

Abstract
Field "A" produces from a mixed-wet formation comprising of fine grained silicilite. The field is a sour light tight oil reservoir with permeability range from 0.001 – 0.1 mD, the only way to flow the existing vertical wells is through hydraulic fracs. Historically the wells have been fracced using water based frac fluids, which have caused severe negative consequences related to well integrity and reduced productivity. With a recovery factor of &lt;1% after 15 years of production, the main challenge and objective lies in enhancing productivity and unlocking the huge volumes of this reservoir through optimizing the field development concept, completion, frac design and execution.
A study was conducted with a recommendation to develop the field by drilling slanted wells with ~10 – 15 frac stages. The frac design in itself is unconventional or hybrid where the targeted frac half length is 5x more than the existing conventional ones. The use of oil based frac fluid instead of water is an opportunity actively pursued to enhance productivity and eliminate issues related to scale and corrosion that in the past have resulted in a loss of production.
Findings of the study have clearly indicated that developing the field with several slanted multi frac wells is economically attractive; with an increase in Net Present Value (NPV) by ~60% and decrease in Unit Technical Cost (UTC) by ~30% compared to developing the field conventionally with vertical wells.
Thermodynamic Data Digitalization: Workflow and Benefits of a Well-Structured Database
Authors: Diatto Paolo , Martin Marco , Drei Enrico , Ciriello Giuseppe , Della Rossa Ernesto , Riva Roberto 
Published: November 2018

Abstract
The knowledge of reservoir fluids phase behavior has always played an important role in oilfield development planning, reserves evaluation and screening of the potential for enhanced oil recovery. Nowadays operators aim more and more at fast-track development of discovered resources, therefore, any anticipation of thermodynamic properties is a business challenge: looking for "PVT-analogues" is the solution proposed in this paper. What adversely impacts massive scouting of PVT data usually is the limit of a small amount of readily available information, also due to the intrinsic complexity of the datasets and of the variety of output formats produced by different laboratories all over the world and over the years. In Eni a new tool for data mining based on the reorganization and thorough digitalization of the PVT archive is in advanced development. Standardization of the laboratory outcomes by templates, automatic loading into a corporate repository, in-house development of software tools for quality control, data mining and advanced statistical analyses, easy access through a properly designed interface: each of these steps is integrated in an upgraded data-driven approach to fluid properties prediction allowing an earlier understanding of the reservoir fluid system.
Managing Drilling Risk Using an Integrated Approach to Real-Time Pore Pressure Prediction
Authors: Patel Nikhil , Penkar Sanjay , Blyth Matthew 
Published: November 2018

Abstract
Pore pressure and wellbore stability estimation in real-time has become a mandatory service in any situation where drilling hazards are expected and particularly in the cases of deep water, exploration, geologically complex and extended reach settings. The basic workflow assumes that under-compaction is the primary cause of abnormal pore pressure generation (Eaton 1975), where an increase in formation pressure is associated with a response in sonic, density and resistivity logs, and models are defined based on this assumption. However, structural deformities, dipping beds or alternate pressure mechanisms could result in a wrong prediction of pore pressure based on what is observed in the shales above, or what is predicted from the standard models. Besides increasing the Eaton exponent or creating different normal compaction trend lines (Malinverno et al., 2004; Sayers et al., 2006) or using an unloading parameter (Bowers 1995), there is the need to define an integrated approach using multiple data sources to construct and constrict the model.
Advanced mud gas interpretation and cavings (pieces of rock not drilled by bit or reamers) analysis have become important tools in real time pore pressure and wellbore stability monitoring and are used to determine the approach to a structural deformity (faults/fractures) or the presence of elevated pressures at the crest of a permeable formation, either due to lateral transfer or gas buoyancy. Analysis of cavings shape, structure and mode of generation helps to determine the current borehole condition and whether the mud weight (MW) needs to be raised to control the problem, or just modifying the drilling parameters would suffice. The presence of connection gas peaks aids the pore pressure analyst to estimate the pore pressure across a permeable formation by associating its magnitude and its relationship to dynamic (equivalent circulating density - ECD) and static (equivalent static density - ESD) environments. The use of Managed Pressure Drilling (MPD) to maintain a constant backpressure across the annulus, negates this fluctuating static to dynamic environment and hence affects the use of mud gas behavior to determine if the prevailing MW column is sufficient to provide static overbalance, but workflows to address this issue have been defined over the years. Although, the industry is currently beginning to use these secondary indicators into their workflows, there is no standard that incorporates these sources into a single, cohesive workflow.
This paper presents an integrated approach to pore pressure prediction and managing drilling risk by incorporating multiple sources of information beyond classical log-based techniques. It demonstrates the value of advanced mud gas interpretation, drilling mechanics interpretation, cavings and drilling parameter analysis to optimize the pore pressure model in real-time and enhance the traditional techniques.
MPD and UBD Hybrid System Achieves Target Depth in Previously Undrillable Conditions in Adhi Field Pakistan: A Case History
Authors: Ashraf Qasim , Khalid Ali , Ali Farhad , Luqman Khurram , Mousa Ayoub , Babar Zaheer Uddin , Hussam Uddin Muhammad , Ullah Safi 
Published: November 2018

Abstract
An operator has drilled more than 32 wells to date in Adhi field, a gas and condensate field in northern Pakistan. The majority of these wells produce from depleted sands and some also produce from limestone reservoirs. The wells range in depth between 8,366 and 11,483 ft (2,550 and 3,500 m).
The operator was in the process of drilling the 8 1/2-in. hole section with the least possible mud weight to minimize the overbalance across the lost-circulation-prone limestone formation. While drilling the section, an unexpected gas pocket was encountered and subsequently required an increase in mud weight. To further add to already challenging drilling conditions, a fault was expected in the middle of the section. This fault was expected to produce total losses. The resulting loss of hydrostatic head would have caused a troublesome well-control scenario.
The above conditions led to an inherently tight drilling window. The operator thus made precise management of wellbore pressures a prime objective. However in conventional drilling, relying on the mud weight and pumping rate for accurate management of wellbore pressures proves highly inefficient, if not impossible.
A managed pressure drilling (MPD) and underbalanced drilling (UBD) hybridized system was devised to enable drilling the 8 1/2-in. hole section. An MPD system that applies constant bottom hole pressure would enable drilling the section with the least possible mud weight and as close as possible to the pore pressure line. In the event that heavy to total losses were encountered because of the predicted fault, the system could be switched over to UBD flow drilling. By switching over to UBD, the equivalent circulating density (ECD) would be reduced further and allow the well to flow while drilling and mitigating losses.
An MPD and UBD system was also expected to offer numerous benefits in drilling, including reduced chances of differential sticking, reduced formation damage, increased rate of penetration and bit life, less washouts in the drillstring and pumps, reduced nonproductive time, and enhanced abilities to execute well control with the pipe in motion without fear of getting stuck.
The MPD and UBD hybrid system was deployed to the location. The operator was able to drill the 8 1/2- in. section to the target depth. The operator commenced drilling with an MPD system but, as expected, heavy losses were encountered. Drilling then proceeded with UB flow drilling until reaching target depth. The hybrid system enabled the operator to achieve target depth, eliminate an entire casing string, and substantially reduce NPT. This paper discusses the planning, design, and execution of the MPD and UBD hybrid system.
Recoverable Oil Mapping and Infill Drilling Optimization for Mixed-Wet Carbonate Reservoirs
Authors: Huang Qingfeng , Sadok Abdel Aziz , Baslaib Mohamed A. 
Published: November 2018

Abstract
Hysteresis commonly exists in relative permeability curves, especially during a cyclic process. To describe hysteresis impact on fluid behaviors, scanning curves are normally applied in numerical simulation models. Hysteresis pertains to saturation history, in which scanning curves and trapped oil saturation are dependent on the initial oil saturation. For mixed-wet carbonate reservoirs that have thick transition zones, initial water saturations greater than irreducible water saturations are distributed conforming to saturation-height functions and rock types. Therefore, water-flood follows the scanning curve path where intermediate saturation reversal occurs, altering the trapped oil saturation.
In the field development plan during water-flooding process, infill drilling identification is traditionally based on simulation model remaining-oil-in-place map or single residual oil saturation attributed to rock types. In this paper, hysteresis-model derived recoverable oil is computed from history-matched model and employed to assist wells planning. An automated infill-drilling program has been coded by considering Killough hysteresis model. First, initial and current saturation at development time are extracted, and end-point residual saturation is identified from saturation functions. Second, the amount of trapped and up-to-date remaining recoverable oil is calculated for each grid cell. Then, the optimum infill locations are identified to maximize contact area with mobile oil. Completion data are generated as output for reservoir simulation.
Since optimum infill locations are identified, better oil-recovery is achieved by implementing the proposed approach, which targets both oil zone and transition zone. Single residual oil by rock types may not help identify the anticipated wells locations in the mature reservoirs. The approach is validated by suggesting less and optimum number of wells while bringing higher recovery according to simulation results. Potential of Enhanced Oil Recovery (EOR) can be further evaluated after quantifying the remaining oil saturation. In the transition zone, larger pores are filled with oil and the trapped oil saturation is lower than that above dry oil intervals, enabling possible wells production in the transition zone.
Initial-saturation-dependent residual oil saturation is used to better map the infill drilling. Rather than adopting the single residual oil saturation by roc type, this approach considers hysteresis-led trapped oil saturation for the preliminary automatic wells screening and optimization prior to dynamic simulation. This process is repeatable and adjustable in line with the development strategy. For the giant and mature oil reservoirs, it demonstrates a better and more efficient development plan.
Measurement of CO2 Diffusion Coefficient in the Oil-Saturated Porous Media
Authors: Jia Bao , Tsau Jyun-Syung , Barati Reza 
Published: November 2018

Abstract
Molecular diffusion is an important EOR mechanism in naturally fractured reservoirs. However, the laboratory-measured diffusion coefficient in the fractured porous media is still limited; and grid sensitivity analysis is missing in the literature when the single-porosity system is applied to history match the pressure decline curve. We aimed to fill the gaps using Radial Constant Volume Diffusion (RCVD) method experimentally to investigate diffusion coefficients at different pressures in hydrocarbon saturated porous media. A special in-house cell is designed to hold the core sample in the center with the annulus around simulating the fracture. The core is initially saturated with oil while the annulus was filled with CO2 at the same pressure. During the measurements, the system pressure declines as gas diffuses into the oil phase until it reaches chemical equilibrium. The pressure decline curve is history matched to determine the diffusion coefficient. The initial pressure is 597 psi, and the diffusion coefficient is determined in numerical models accordingly. Molecular diffusion coefficients are estimated at different experiment periods to reveal the pressure-dependency. Models with different grid numbers are applied to reveal the scale dependency when including molecular diffusion in reservoir simulations. Besides, flow characteristics in the RCVD system are characterized and capillary pressure effect is investigated in this study.
Multi-Objective Optimization to Predict Minimum Temperature for Efficient BTEX Destruction to Minimize Fuel Gas Consumption in Sulfur Recovery Units
Authors: Rahman Ramees K. , Ibrahim Salisu , Raj Abhijeet 
Published: November 2018

Abstract
Benzene, Toluene, Ethylbenzene and Xylene (BTEX) present in feed gases to Sulfur Recovery Units (SRU) cause frequent catalyst deactivation. BTEX can be oxidized at the recommended temperatures above 1050°C. High temperatures are achieved through feed preheating and co-firing acid gas with fuel gas. However, temperatures above 1050°C is not required when BTEX concentration is low. A multi-objective optimization approach is deployed to minimize feed preheating temperature and fuel gas co-firing, while maintaining high BTEX destruction. A well validated model for Claus furnace from previous studies was used for furnace simulations. Claus furnace was modelled using Chemkin Pro, while catalytic section (including condensers, re-heaters and incinerator) was modelled using Aspen Hysys (Sulsim). MATLAB was used as a platform to link Chemkin Pro with Aspen Hysys. Optimization was performed in MATLAB using genetic algorithm. The objectives of optimization were to 1) Maximize sulfur recovery, 2) Minimize fuel gas consumption to furnace, 3) Minimize air and acid gas preheating temperature. As a constraint, total BTEX at waste heat boiler outlet (WHB) was maintained below 1ppm. The optimization range for fuel gas flow rate was from 29 to 2034 nm3/hr, air temperature from 180 to 360°C and for acid gas temperature, 180 to 230°C was considered. The feed properties and physical dimensions of SRU were obtained from an industrial SRU plant. Results show that furnace temperature of 1028°C needs to be maintained for maintaining BTEX destruction for the given feed condition examined. Thus, fuel gas co-firing can be reduced from base case value of 1773 nm3/hr to 29 nm3/hr, while air preheating temperature can also reduce from 325°C to 223°C. This can assist in reducing operational costs in sulfur recovery units considerably. The present work predicts the ideal conditions for BTEX destruction in SRUs based on inlet feed conditions. This approach can be used to seek favorable means of optimizing Sulfur recovery, decreasing fuel gas consumption in sulfur recovery units to reduce operating cost.
Overcome Slug Related Operational Issues in Brownfield Facilities by Using Bypass Pigging
Authors: Kollamgunta Saikiran , G. V. R. A. Srinivasa Rao , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2018

Abstract
One of the major challenges in the upstream oil and gas industry is de-bottlenecking of existing slug catcher/ inlet separator system during facilities up-gradation or due to changes in production rates for any other reasons. It is often found that upgrades or changes result in increased slug volume from the upstream pipelines thus making existing slug catcher or separators inadequate to handle the increased load. Even in cases of normal pigging not involving debottlenecking of existing facilities, production rates are required to be lowered. This is done as excess liquid slugs generated due to pigging may show severe operational problems in terms of level and pressure fluctuations in a separator leading to poor separation, potential liquid flooding, increased flaring, emergency shutdown and production loss. The use of by-pass pigs can effectively reduce the liquid arrival rate at the slug catcher over conventional approach by delivering a more uniformly mixed fluid even at relatively higher production rates. It thereby reduces the slug volume and hence, the requirement of increased surge capacity. Further, in brownfield applications, it enables optimal use of existing assets or avoiding new slug catcher.
Operators are reluctant to reduce the production flow rate to very low value for pigging, as this normally results in reduction in revenue. Bypass pigging, as compared with conventional pigging, is able to reduce the pig velocity even at relatively higher production rates. It, however, requires careful evaluation and design as in many cases, such as well fluid having wax, solids or high asphaltenes may result in blockage of the bypass holes thus impacting the effectiveness of the operation. Transient modeling and simulation of bypass pigging using OLGA Dynamic Multiphase Flow Simulator has been performed to address such issues.
This paper describes the strategies to address de-bottlenecking challenges due to increased surge volumes to be accommodated in the existing slug catcher/ separator system and use of by-pass pigging to overcome these. The application of the technique used i.e. bypass pigging is demonstrated by transient multiphase simulation using OLGA dynamic simulator. Proposed design solutions are based on NPCC's extensive and successful experience in tackling challenging Brownfield projects.
Drilling Cube - A State of the Art & Innovative Dynamic Well Data Platform - Monitor Wells Delivery Performance, Predict for Enhancement Opportunity & Decision Making & to Manage Well Cost More Efficiently
Authors: Al Shamsi Juma , Zahran Hussain 
Published: November 2018

Abstract
Drilling a successful well means reaching the target on time and on budget, getting a clear insight on the well operations data can provide a clear view of any risk that would impact the well delivery. With the analysis of the drilling activities data drilling teams can build the corrective actions and define the productivity best practices to apply for their future activities.
When highlighting "data analysis" we refer to the process by which large amount of raw data is reviewed in order to determine conclusions based on that data. With the number of wells ADNOC Onshore drill every year it gives a clear view of the amount of data that is being generated from each operated rig and the massive amount it is required to build an insight on this data.
The teams in ADNOC ONSHORE utilized the latest tools and technologies to build Drilling Cube, using big data techniques the massive amount of drilling data across different data sources were aggregated to a unified data model where drilling data is segmented to provide the required data insight, some of the measures being visualized includes Invisible Loss Time, Non Productive Time, Rate Of Penetration Analysis, Well Cost Analysis, Well Activities Breakdown Analysis
With the above mentioned and the fact that wells are becoming more challenging to drill, ADNOC ONSHORE decided to build a data analytical dashboard "Drilling Cube" by which drilling teams can get a full insight on the drilling operations and drilling management are able to proactively take the necessary actions on time.
By adding Drilling Cube as part of the tools drilling engineers utilizes to manage their day to day activities, a number of benefits are gained, the following are just some of the benefits of the data insight drilling engineers are getting:
Allows for the identification of important drilling operations trends Helps drilling engineers identify performance problems that require some sort of action Drilling operations data is visualized in a modern charting capabilities, which leads to faster and better decisions Full awareness regarding the drilling activities
Drilling Cube is currently providing a data insight from data that is being aggregated from different systems, the roadmap for the platform is to move towards a more advanced stage to apply techniques where it delivers predictive analytics and forecasts based on real time data and machine learning approaches, this will maximize the drilling teams insight over every day well operations and will help minimizing the risks surrounding the drilling operations.