bluuebunny/crossref_metadata_2025_split huggingface dataset:
Consolidated Approach for Effective Zonal Isolation, Evaluation and Remediation
Authors: Yugay Andrey , Nestyagin Andrey , Vorozhikhin Sergey , Silchenok Mikhail , Daghmouni Hamdi 
Published: November 2019

Abstract
Over the ages of the well drilling history, primary and remedial cementing remains one of the most challenging activities with direct effect on the well life and well integrity status. This paper is based on the actual lessons learned and latest best practices in zonal isolation of Company fields developed according to business requirements during drilling and workover operations. It covers the aspects of primary cementing in two main types of casing design, and describes major challenges associated. Authors tried to define a clear criteria on what can be considered as the minimum acceptable zonal isolation, what are the issues associated with its evaluation, what needs to be done in order to meet those criteria. Additionally, there is an analysis done on the direct impact of the cementing job on the well life. Particularly, the focus is made on well integrity related issues and remedial solutions to cure them based on successful case histories. The paper answers on many questions related to the consequences of the poor cement isolation (up to well control incidents), as an actual lessons learned collected over the 60 years of operation.
The impact of the casing design on the well integrity status is analyzed based on the results of wellhead pressure monitoring of around 4,000 wells. It includes revision and analysis of cement evaluation logs of wells with behind casing communication (sustained pressure in "B" annulus) along with the challenges associated with the diagnostic investigations of the leak source. Various cementing remedial techniques are described with pros and cons analysis and actual case histories including results of post-job wellhead pressure monitoring. The subject of swelling phenomena of soft shale formations and its effect on acoustic based tools for cement bond evaluation is touched as well. Finally, the paper contains interesting results of the recent corrosion logging campaign that reveals a correlation between casing condition and casing design.
Single Point Gas Lift SPGL, A Quick Win Retrofit Gas Lift Application to Maximize Oil Production and Recovery in Greater Bongkot North Field, Thailand
Authors: Peerakham Chatchanakorn , Kruennumjai Sineenat , Junmano Tanawat , Boonchun Cholavit , Ngamkamollert Krit , Ut-ang Pradondate , Whangkitjamorn Jugkapun , Sompopsart Suwin 
Published: November 2019

Abstract
In Greater Bongkot North (GBN) Gas Condensate Field located in Gulf of Thailand, many oil wells have recently encountered liquid loading problems. Numerous attempts of gas pressurizing and lowering wellhead pressure have been made but could not sustain continuous oil production. This paper describes the use of innovative technique, Single Point Gas Lift (SPGL) Application, to revive oil production and increase oil recovery from liquid loading wells without the need for an expensive workover operation.
SPGL is a retrofit retrievable gas lift straddle that can be installed in the existing production tubing via slick-line unit. This fit-for-purpose solution requires 3 main stages of planning and execution. Firstly, design parameters are identified by simulation software e.g. injection depth, injection rate and pressure. Then, gas lift vale (GLV) is installed by punching the tubing at designed depth, followed by installation of gas lift assembly across the punched depth which includes orifice, check valve and pack-off. Lastly, gas supply is injected into annulus and passes through the installed GLV into production tubing.
The pilot test was conducted at well Bongkot-1, a liquid loaded horizontal oil well. SPGL installation was completed successfully followed by deployment of nitrogen injection unit as gas supply in order to prove the concept of SPGL. The gas lifting operation was begun with well unloading and then varying injection rate to determine an optimum gas injection rate. As a result of total 16 hours of nitrogen injection, the cumulative oil production volume of 3,000 STB was realized, indicating the success of the SPGL application. Consequently, long term production phase by utilizing gas supply from high pressure donor well is being implemented.
The result proves that SPGL helps to not only revive liquid loading well but also recover more oil reserves and generate more revenues with low cost and simple operation. In 2019, at least 4 oil wells have been scheduled for installation of SPGL application and later with more proven track record of success, it could be extendedly applied to other oil/gas condensate wells, having liquid loading problems, in Greater Bongkot North Field and other fields operated by PTTEP.
A Review of Pore Structure Characterization of Unconventional Tight Reservoirs
Authors: Mustafa Ayyaz , A.Mahmoud Mohamed , Abdulraheem Abdulazeez 
Published: November 2019

Abstract
The global growing energy demand driving the industry attention towards unconventional oil/gas resources due to limited conventional resources. Huge reserves of unconventional makes them promising and draw the industry attention, however oil/gas is stored in micro to nano scale pores with poor connectivity. It is very essential however difficult to quantify the flow characteristics in porous media in unconventional reservoirs due to complex pore network, irregular geometry of pore throat and non-homogeneous pore size distribution.
Various experimental techniques to determine quantitative and qualitative characteristics of pore systems have been studied including scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), micro/nano computed tomography (XCT), and fluid invasion (mercury injection capillary pressure and gas adsorption/desorption). The comparison analysis of results has been carried out that exhibited the ability of these techniques to get the information about the pore size distribution and limitations for different pore sizes. Best and reliable technique for characterizing the pore structures in unconventional has been identified.
SEM and FE-SEM are only able to provide the qualitative parameters for pore morphology, distribution and connectivity of pores. Three-dimensional image of pore structure and network could be studied through micro-CT scan images however, its high expense and huge processing time due to observation of small region at certain resolution make its use limited. Nitrogen adsorption is only able to study the micropores in tight sandstones but it destructive nature limits its usage. Pressure controlled mercury porosimeter technique is not able to determine the microporosity directly and determine the throat. It does not provide pore throat distribution. Application of high pressure may damage the pore structure. However, this mercury injection constant pressure rate can be applied for yielding both pore sizes and capillary pressure of pore throats. Both small throat and large pore body can be investigated through this technique, but this technique has limitation in maximum injection pressure. NMR is able to provide the qualitative and quantitative delineation of pore structures features such as pore throat distribution, sizes, and pore fluid saturation, total and effective porosity, and permeability directly if supplemented with other techniques.
Detailed analyses of different analytical techniques resulted that none of the technique is able to fully characterize the pore structure of unconventional tight rocks. Combination of more than one technique is the best solution for complete description and accurate determination of pore structure characteristics.
Optimizing Automated Well Testing for the Unconventional Oil Field using a Modular Approach
Authors: Baaren Sander , Malone Ryan 
Published: November 2019

Abstract
Well testing equipment for unconventional onshore applications generally comprises a sand removal unit (Desander), a dual choke manifold, a test separator with metering, various types of tanks for temporary storage and in some cases a flare. This equipment is typically interconnected through high pressure temporary flowline generally referred to as flow-iron, which is made up from modular components that are joined by quick connect hammer unions. Installation of the equipment and the well testing itself is labor intensive. Personnel is on location 24 hours a day, working on or near high pressure piping and climbing onto open top tanks during well testing. This results in significant labor costs and exposes personnel to numerous health and safety risks.
This paper starts with introducing a modularized Automated Well Testing system (AWT) which has been developed to rig-in and out faster, minimize personnel exposure to health and safety risks, minimize transport cost, reduce footprint and eliminate greenhouse gas emissions to operate the unit. A first unit has been built and applied at various shale plays across North America during the past two years. Learnings and conclusions from these applications are summarized and used to evaluate the design.
First Wired Drill Pipe Deployment in Adriatic Sea
Authors: Salomone Andrea , Burrafato Sebastiano , Ricci Maccarini Giorgio , Poloni Roberto , Gioia Valeriano , Concas Antonio , Tangen Geir Ivan , Huse Arve , Antoniani Lucio , Andersen Mats , Zainoune Sanna 
Published: November 2019

Abstract
This paper presents the positive results of the first deployment of wired drill pipe (WDP) technology and along-string measurement (ASM) tools in drilling operations in the Adriatic Sea. The WDP system was used within the frame of a multi-objective testing program, in conjunction with an experimental downhole tool.
The system allowed transmission of real-time, high-density, low-latency data from logging-while- drilling (LWD) tools and from ASM subs. These tools provided temperature, annular/internal pressure, rotation, and vibration data. This was the first time WDP and ASM tools were used by an operator in the Adriatic Sea. The system was also used for activation and communication with another experimental downhole tool on this project.
The high-speed telemetry system made it possible to achieve impressive operational and performance benefits. Annular pressure measured along the string provided a better understanding of the drilling mud condition and behavior along the wellbore, thereby allowing the operator to stay in the safe mud-weight window and helping them to avoid unintentional hole fractures or collapse.
During pumping in and out of hole, swab and surge were also monitored closely with downhole, real- time measurements from the ASM tools. The same effects were controlled after drilling each stand, when the interval drilled was reamed to ensure sufficient hole cleaning.
While drilling, the system raised the rate of penetration (ROP) limit by removing constraints on data acquisition while still providing the confidence that the hole was being cleaned while drilling. Drillstring vibration was recorded as well, and potential benefit in preventing premature failure of downhole tools were highlighted.
The test verified that improved drilling performance was enabled using WDP technology. Awareness of downhole conditions and a substantial reduction in risk were also benefits. In addition, the technology unlocked bidrectional communication and control with modern downhole tools.
Establishing State of the Art Unified Technical Data Center to Harness the Power of Legacy Data for Future Opportunities- An E&P Success Story in Sharjah, UAE
Authors: Jain Siddharth , Al Hamadi Masoud , Stewart Neil , Khan Sikandar , Malik Arshad 
Published: November 2019

Abstract
Capitalizing on untapped potentials and quantifying risk is the key to success in a turbulent commodity industry. With an internal initiative to capture national knowledge and to safe guard sovereign data, Sharjah National Oil Corporation (SNOC) embarked on a multi-year journey to find, archive, digitize and integrate the entire E&P data in the Emirate dating from 1966 till date. The challenges and accomplishments of effective data management are demonstrated as a successful case study.
Securing investment in a country’s petroleum industry demands for government agencies to add value to its oil & gas assets by making them readily available, globally. To do so, one of the most important steps was to effectively catalogue and manage technical information from both past as well as present exploration and production initiatives. Scattered archives for multi-disciplinary data including well reports, logs, maps, seismic sections, tapes, G&G studies, cores, cuttings and digital databases was centralized in one repository for the Emirate. A unified data quality assessment, metadata capture & naming convention was established for all data types including a technology infrastructure to enable maximum utilization and integration of data into future projects. Ambitious to exploit its current technical assets by evaluating historic data to attain maximum benefit to SNOC, partners and global investors; SNOC adopted a cohesive and effective physical & digital asset management approach with a phased methodology in early 2016. This data management activity was classified extremely critical to the E&P current and upcoming projects by laying the foundation for drilling SNOC’s 1st Exploration well, a successful Farm-out bid round, quantifying workover opportunities, regional interpretation and performing field development simulations. Centralizing and integrating the data management function enabled the operator to identify data gaps and work on fulfilling them to successfully establish a regional technical data center. The paper discusses the challenges of gathering, extracting and incorporating legacy data; shedding light on the value it generated in paving the way for a digital transformation in SNOC’s E&P business.
Fluctuating technological, political and business influences add to the volatility and risk in the oil and gas business. The framework and success of future opportunities is reliant on the data used to quantify them. The method chosen for this journey was to modularize the data management project and structure best in class industry solutions for each aspect. The architecture for data management implemented is cost-effective; which is scalable and upgradable with minimum effort into a digital hub of information & knowledge management.
Full Robotic Drill Floor as Advanced Rig Automation
Authors: Cappuccio Pasquale , Burrafato Sebastiano , Maliardi Alberto , Ricci Maccarini Giorgio , Taccori Daniele , Dalla Costa Riccardo , Raunholt Lars , Larsen Øystein 
Published: November 2019

Abstract
Early studies indicate a large potential of savings in rig time and elimination of manual operations on the drill floor, when introducing robotic drill-floor equipment on the drill floor. Robots can carry out pipe, casing and tool handling tasks in a safe, fast, consistent and precise manner.
For obtaining a digitalized, fully automated drilling operation, electric robotic equipment is a key enabling technology.
Since 2016, Eni has been directly involved, together with Canrig Robotics, in the technology development process for the robotic drill floor, being part of two Joint Industry Projects (JIPs) in Norway, named "Offshore Pilot of Drill Floor Robot" and "Demonstration of Automated Drilling Process Control". The aim of such projects is to install and test robotic equipment on rigs and to demonstrate the full automation of drilling operations through the integration with an advanced control system.
A fully robotic drill floor requires state-of-the-art technological and industrial level innovation, which forms a basis for performing drilling & completion operations safely, reliably and consistently.
This paper describes the results of a preliminary feasibility study performed by Eni in collaboration with Canrig Robotics concerning the installation of such equipment on two different rig designs, three land rigs and two drill ships, in order to find the best candidate(s). The analysis contains data collection, operational descriptions, modification and installation works, value propositions and business cases.
The value proposition from using robotic equipment includes faster tripping due to consistent and seamless handling. A high number of manual operations can be saved by robotic handling of subs, pup joints, safety clamps etc. Stand-building can be made fully automated and can take place in parallel to e.g. drilling in the well center.
Preliminary results show a significant potential improvement on KPIs, with an estimated time saving of 20 to 60 days per rig yearly. At the same time, HSE issues are widely mitigated, since operations can be performed effectively and consistently by robots, thus removing people from harm's way on the drill floor.
Casing Running Mechanization on the Semi-Submersible; Maersk Discoverer
Authors: Hegab D. , El Kholy S. , Banger T. , Hoelterling C. , El Shenoufy O. , Boers R. , El Wakeel W. , Najwani M. , Mobarak H. , Courtney B. , Muhiuldin G. 
Published: November 2019

Abstract
One of the most serious red-zone hazards on a rig's drill floor is in casing running operations. Manually operated power tong hanging on a rig floor tugger required up to six people to be present in the red zone of the drill floor. In this respect, it was decided to evaluate the latest technological advancements, and work on an improved solution to casing running operations. The challenge on the Maersk Discoverer is the main well center roughneck design, which has historically prevented the team from using an existing mechanized solution from the market. The Casing Running mechanization project was piloted on the Maersk Discoverer rig, in order to mechanize the casing and tubing running operations. Weatherford has specifically designed a bespoke adaptor that fits the Column Mounted Roughneck (CMR) on the main well center allowing for a remotely operated casing running operation. The adopted design overcomes the challenge of tight space between the tong and the well center which prevented the mechanized solution in the past. Weatherford casing and tubing tongs are remotely operated through Weatherford's mechanized control system. This Pilot approach has been installed and tried with multiple casing and tubing sizes. This project brought remarkable results impacting the safety and the performance of our operations through two outcomes. Zero people in the red zone on one hand and on the other hand, improving efficiency of handling the tongs in a controlled manner avoiding excessive and uncontrolled movement of these heavy loads. Consequently, hands-free casing running operations were successfully implemented!
Hydrocarbon Belts
Authors: Noufal Abdelwahab , Parra Humberto 
Published: November 2019

Abstract
Hydrocarbon belt is as a tectonic zone along which most hydrocarbons accumulate. Five major hydrocarbon belts are identified on the Arabian scale that are consistent; possess similar trends and geologic history. These are the NE-SW trend of the onshore Abu Dhabi fields, the N-S trend of Saudi Arabia, Kuwait and southern Iraq, the NW-SE trend is represented by Southern-Central Iraq, and the E-W trend in northern Iraq, Syria and Turkey. The fifth category includes fields related to salt doming events, which are not characterized by a systematic trend but can be restricted to specific areas where salt movements played a major role. Understanding these belts and their geologic concepts can predict new exploration potentials between or within the existing fields.
The extent to which the stress state has influenced hydrocarbon distribution through geologic time can be directly seen on the fields maps. An important element on the existence of the hydrocarbon accumulation belts are that almost all fields in the Arabian plate and the foreland basin have not been obliterated by subduction. The continental collision of the Arabian plate with Eurasian plate produced high-pressure/low-temperature structural belts forming hydrocarbon traps resulting from deformation. This lead the hydrocarbon to move from high-pressure to low-pressure zones, leading the hydrocarbon migration and entrapment process towards low-pressure regions.
Many wells drilled with direct measurements of in situ stress allows the estimation of the direction of the stress vectors. Using the local stress orientations in Abu Dhabi while linking this to tectonic events and combining with the Arabian stress trajectories fed the methodology and workflow presented in this paper.
The results show that the stresses affecting Abu Dhabi can be categoriesed into: (1) The differential stress generating detectable azimuthal variations due depth; (2) The pre-inherited stress trajectories; and (3) the stresses related to the wrench fault segments. The pressure associated with these stress trajectories is the main driver for the hydrocarbon migration and filling of the traps. Applying these stress trajectories with the variances in the state of stress of different stratigraphic layers, enables understanding of where the hydrocarbon is trapped.
Prediction of the migration trajectories is a very useful tool for exploration, specifically for the identification of new leads and plays, as well as for constructing new theories on the equilibration of the fluid levels and observations of residual oil below the current established free water levels.
Research on Hydrate Risk Prediction in Deepwater Submarine Natural Gas Transmission Pipelines
Authors: Liu Wenyuan , Hu Jinqiu , Sun Fengrui , Sun Zheng , Chu Hongyang , Li Xiangfang 
Published: November 2019

Abstract
Hydrates generation-blockage in submarine natural gas pipelines has always been related to the safety of deepwater natural gas production and transportation. However, the current hydrate formation risk prediction in subsea pipelines is still immature.
In this paper, a model for evaluating the risk of hydrate formation in submarine natural gas pipelines has been established. The model has been applied and the sensitivity analysis of typical factors has been carried out. The results show that: (a) owing to the low temperature of the seabed, hydrate formation region (HFR) often exists in submarine pipelines. Avoiding HFR by injecting inhibitors is the key to ensure the safe transmission. (b) the decrease of gas temperature in the pipeline is determined by the heat loss of gas from inside to outside of the pipe. At a lower gas transport rate, the decrease of gas temperature is more significantly affected by the heat exchange rate. (c) at the same gas transport pressure and temperature, the pressure drop increases with the increase of gas transmission rate, while the temperature drop and the length of HFR decrease with the increase of gas transmission rate. (d) at the same gas transport rate and pressure, the pressure drop in the submarine pipeline is not significantly affected by the gas transport temperature, but the gas temperature at the end of the pipeline increases with the increase of the gas transport temperature and and the length of HFR decreases with the increase of gas transport temperature. (e) at the same gas transport rate and temperature, the temperature drop and HFR in the submarine pipeline is not significantly affected by the gas transport pressure, but the pressure drop loss decreases gradually with the increase of gas transport pressure. (f) reasonable setting of gas transport temperature and gas transport rate can help to reduce the hydrate risk and consumption of inhibitors in the submarine natural gas transportation.
Accurate prediction of hydrate risk in deepwater submarine pipelines is essential for safe gas transportation. The research provides the theoretical guidance for safe and efficient natural gas resources development and transportation.