bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovative Biodegradable Intermediates for Sweet Corrosion Inhibitors
Authors: Feche Maxime , Crabtree Alla
Published: November 2019

The corrosion of carbon steel tubing, pipelines and process equipment during Oil and Gas production due to salt water saturated by corrosives gases, such as carbon dioxide and hydrogen sulphide, can lead to substantial environmental and economic consequences. A lot of different technics are used to reduce the corrosion in the pipelines: use of specific alloys, biocides or H2S scavenger. One of the proven and most widely used mitigation techniques is the addition of film-forming corrosion inhibitors into production streams. Those compounds have affinity with metals and will thus form a film at the surface of the metal, creating an electric resistance between the metal and the corrosive species.

The products used offshore and released in the North Sea are currently controlled by OSPAR Convention requiring to meet environmental criteria on three different parameters: Biodegradability, Toxicity and Bioaccumulation. Passing 2 out of 3 criteria is enough to comply with the OSPAR Convention.

This paper presents the performance results obtained with novel biodegradable compositions used as corrosion inhibitors for continuous injection with a thermal stability up to 135°C. A superior performance against sweet corrosion was obtained at 80°C in brines of different salinity, both in the presence and absence of a hydrocarbon phase. Additionally, new compositions exhibit low critical micelle concentrations and their structure can be further modified to adapt to various salinity conditions.
Deformable Micro-Gel for EOR in High-Temperature and Ultra-High-Salinity Reservoirs: How to Design the Particle Size of Micro-Gel to Achieve its Optimal Match with Pore Throat of Porous Media
Authors: Yuan Chengdong , Pu Wanfen , Varfolomeev Mikhail A. , Wei Junnan , Zhao Shuai , Cao Li-Na
Published: November 2019

Conformance control treatment in high-temperature and ultra-high-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable micro-gel that can be used at more than 100 °C and ultra-high salinity (TDS > 200000 mg/L, Ca2+ + Mg2+ > 10000 mg/L), and present a method for choosing the suitable particle size of micro-gel to achieve an optimal match with the pore throat of core.

First, the particle size distribution of micro-gel was analyzed to decide d50, d10 and d90 (diameter when cumulative frequency is 50%, 10% and 90%, respectively). Core flooding experiments were conducted under different permeability conditions from 20 to 900 mD. The migration and plugging patterns of the micro-gel were studied by analyzing and fitting injection pressure curves together with the change in the morphology of produced micro-gel analyzed by microscope. Finally, a quantitative matching relation was established between the size of micro-gel particles and the pore-throat size of core, its effectiveness was verified by evaluating plugging ability in subsequent water injection process.

The migration and plugging patterns were divided into three patterns: complete plugging, plugging – passing through in a deformation or broken state – deep migration, and inefficient plugging – smoothly passing through – stable flow. The second pattern can be further divided into three sub-patterns as strong plugging, general plugging and weak plugging. Based on the five patterns, a quantitative matching relation between the size of micro-gel particles and the pore-throat size of cores was established by defining three matching coefficients α=d10/d, β=d50/d, γ=d90/d (d is the average pore throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance coefficient) in sequent water flooding process after the injection of 1.5 pore volume of micro-gel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ <6. In this scenario, the deformable micro-gel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation can provide an indication for the quick determination of the suitable size of deformable micro-gel for conformance control processes in field application, including profile control and water-shut off treatment.
Consolidated Approach for Effective Zonal Isolation, Evaluation and Remediation
Authors: Yugay Andrey , Nestyagin Andrey , Vorozhikhin Sergey , Silchenok Mikhail , Daghmouni Hamdi
Published: November 2019

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

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

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

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

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

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

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

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

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

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.
Casing Stretch Simulation in Extended Reach Wells Prevents Unintentional Blockage of Flow Path While Displacing the Slurries to the Annulus in a Primary Cement Job
Authors: Corona Mauricio , Ruzhnikov Alexey , Sebbane Slimane , Jain Bipin
Published: November 2019

This paper describes the process followed to explain the mechanical blockage in the flow path observed while displacing the cement slurries in long casing strings set with short rat holes. In most of the cases, those blockages ended with amount of cement left in pipe and significant remedial works.

All the incidents were investigated involving casing design experts, cementing specialists and data analysts to understand the root causes. Mud logging unit, cementing and rig sensors data from several cementing jobs were analyzed in an integrated and holistic approach. Four different software’s were used to simulate and prove the theory that total elongation of the casing was enough to exceed the rat hole length bringing the casing in contact with the bottom of the well, and therefore blocking the flow path.

In all the incidents, the issue was observed at the beginning of the slurry displacement stage where the entire volume of the cement was still inside the casing. Other possible causes of blockage (cement contamination, mechanical failures, loss control material,…) were also checked and ruled out.

Hookload data was available to be analyzed whenever a conventional wellhead was installed, and the casing was held on the elevators during the cementing job. However, in some cases this information was not available as a compact wellhead was used. For those cases, it was necessary to drill out the shoe track using LWD to detect the location of casing shoe.

Recommendations were made to add new loads the current casing design. Results will define the minimum rathole length and the maximum tension at surface experienced by the casing during the cementing job in both static and dynamic conditions. Also, it is important to properly estimate the rathole the physical measurement of the casing joints in the tally can carry measurement errors.
Interbed Demultiple Workflow for Low Relief Structures Onshore Abu Dhabi
Authors: Roig Carlos , Elmansoury Alaa , Glushchenko Anna , Vargas Jose Edgardo , Utami Yeni Prasetyo , Seo Youngtak , Al Ghafri Thuraya Mohammed , Liu James , Kim Dongoh
Published: November 2019

Good quality seismic data are essential for seismic reseirvoir characterization, from seismic applications (wavelet estimation, low frequency model building, seismic velocity calibration and time to depth conversion) to petro-physical interpretation, rock physics modelling and hard data in deostatistical modeling. Surface seismic data need to possess the necessary level of quality to make the advanced inversion techniques successful in providing the reservoir characterization results to be input into the static models.

Interbed multiples occur in all types of seismic datasets and are challenging to address, directly and negatively affecting structural and stratigraphic mapping, as well as extracting concise petrophysical attributes from the seismic data. This is particularly a problem for deep and fractured reservoirs, where strong internal multiple contamination increases the ambiguity of the interpretation and inversion of the seismic data, leading to misleading reservoir characterization, ultimately affecting well construction and placement.

These interbed multiples can appear at a very similar timing and amplitudes to primaries due to comparable velocities which makes it difficult to differentiate from primary energy in areas with relatively flat geology. In current paper we will demonstrate the demultiple workflow for low relief structures in Abu Dhabi. To address the specific challenges, Extended Interbed Multiple Prediction or a combination of methods presented. The multiple attenuation workflow described in this work follows forward modelling and adaptive subtraction with primary protection approach, improves the preconditioning of seismic for pre-stack inversion over the target oilfield. "The output seismic data after the optimal multiple attenuation workflow provide a superior seismic inversion and a suitable input for reservoir assessment and delineation of the thin carbonates reservoirs present in UAE" (Melo, Glushchenko et al. 2017).
Decline Curve Analysis Using Artificial Intelligence
Authors: Masini Shashipal Reddy , Goswami Shubham , Kumar Aditya , Chennakrishnan Balaji
Published: November 2019

DCA (Decline curve analysis) is the most followed and useful approach for the short-term production forecasts. The objective of this paper is to demonstrate automated DCA using AI (Artificial Intelligence) Techniques.

Cutting-edge clustering techniques were used to identify the data points where the decline curve is applicable. As the well's pressure depends on factors such as production rates, field and surrounding well's production rates, Multi-variate regression was used to increase the pressure prediction's robustness. As the production forecasting is a time-series sequence problem, models like XGBoost (Extreme Gradient Bosting Algorithm), RNN (Recurrent Neural Networks) i(Lipton 2015) were chosen to perform this regression. After training the model on the data, the model's predictions were combined with outputs of well-modelling to assess the well's flowing ability at each timestep.

The solution removes anomalous data and perform automatic DCA in a scalable manner. The observed and calculated data have a very good agreement (very less root mean square error and a deviation less than 5%). Probable Well ceasure times were predicted with very minimal uncertainty (with an Average deviation of 3 months).

The novelty of this approach is the ability of the AI and machine learning algorithms to perform the DCA automatically and its scalability. It frees the engineers from data gathering, anomaly removing and rate break identifying process leading to quicker interpretations and effective decision making. This approach can also be combined with well modelling using AI to predict the probable well shut-in timelines.
Real Time Operation Centre Monitoring and Optimizations in Highly Deviated Deepwater Development Wells in Malaysia
Authors: Ng Mui Ted , Lum Terry , Yeap Fabian , Abdul Talib Sa'aid Hazley , Zainal Abiddin Mohamad Sukor , Hooi E-Wen
Published: November 2019

As the search for hydrocarbon offshore runs deeper and farther from land, it is best we gear ourselves to embrace what it takes for delivering highly deviated deepwater development wells to push the frontiers of petroleum extraction. This paper discusses the monitoring and optimizations of deepwater wells operations in Malaysia by the Shell Malaysia Exploration and Production Real Time Operation Centre (SMEP RTOC).

The scopes of monitoring and optimizations discussed in this paper include: Hydraulics management in narrow pressure margin drilling, including modelling, optimization, measurement and monitoring of equivalent circulating density (ECD).Engineering support in pre-drill study for Managed Pressure Drilling (MPD) application.Mitigation of drilling vibration in highly deviated wells, especially stick-slip vibration.Hole cleaning modelling, monitoring and optimization.Drilling roadmaps and database are archived by RTOC for future wells reference.Drilling operations performance tracking and benchmarking.24/7 Top Tension Riser, Hawser and mooring lines tension monitoring.

Deepwater drilling operation costs are typically significantly higher than shallow water and land rig operations. This is partly due to higher rig rates in deepwater operations. In this case any reduction in Invisible Lost Time (ILT) and Non-Productive Time (NPT) may result in significant cost reduction. Like a safety net that catches anomalies that slipped the first line of defense, RTOC monitoring has the facilities and trained capabilities to oversee and optimize the operations in totality both during real time and post run. An investment in RTOC services in exchange of more cost efficient and safer operations will be justified in the paper.

Real Time Operation Centre (RTOC) is becoming more indispensable over the years. Hawk-eyeing operations in areas where attention is diluted by other tasks on the rig, could probably be the insurance needed in every future oil and gas drilling. The methods, procedures and processes in well operations will definitely advance with time and further developments and innovations in this subject will be closely followed within the industry.
Performance Prediction and Optimization of Acid Fracturing Based on the Dynamic Differential Modeling Method
Authors: Zhao Xing , Wang Hehua , Lu Lize , Liu Zhibin , He Enjie
Published: November 2019

For prediction of the post production of acid fracturing, a numerical method has been introduced in this paper. This prediction approach is developed by the dynamic differential modeling method for forecasting single well acid fracturing performance. In this study, the average production during 30 days and fracture geometry after acid fracturing were determined as predicted indices. Fifteen parameters were considered as influencing factors consisted of geological, reservoir and treatment parameters. The field data of predicted indices and influencing parameters were collected from the data of 7 acid-fractured wells in the XB oil field. The historical data was input into the dynamic differential model to establish and discretize the relation functions. Three target well were chosen and their corresponding influencing factors were used to calculate the predicted indices. The results showed that for the target wells, the modeling predicted indices were fairly close to the real numbers. This model is practical for the engineer in the field since the input parameter acquisition is accessible from the common oil field data. It could help the engineers to optimize the acid fracturing treatment design by correlating the scale of the treatment.
A Case Study on Reducing Uncertainty by using Correct Procedure & Desaturated Reservoir Fluid on NMR Core T2 Bound Fluid Cut-Off Analysis for Gaint Abu Dhabi Onshore Carbonate to Compute Reliable Field Wide Swirr Analysis from NMR Logs
Authors: Singh Maniesh , Dey Swapan Kumar , Farooq Umer , Radwan El Sayed , Rajwade Sachin , Tombokan Xenia , Mendoza Rafael , Hannon Loay , Watson Rayvan
Published: November 2019

The estimation of bulk volume of irreducible water (BVI) is one of the earliest and the most widely used applications of NMR logging using either a fixed T2 cutoff value or Spectral BVI. NMR BVI assumes that bound fluid resides in small pores and producible free fluids (FFI) resides in large pores where the pore throat and pore body sizes are often related. As T2 distribution is related to a pore body size, a T2 cutoff can partition BVI & FFI.

In Carbonates there is no clear relationship of pore throat size to pore body size, thus measuring BVI T2 cutoff per rock type becames important although challenging. This paper covers the importance of following correct laboratory procedures, quality assurance of laboratory experimential data, and innovative methods to determine reliable T2 cutoff which otherwise are very low and not practical to apply in the NMR log domain.

NMR analysis was performed with a 2 MHz field instrument using a CPMG sequence and sufficient echo trains to acquire reliable T2 distribution. T2 cutoff was determined on core samples with a wide range of porosity, permeability, and rock types. Core samples were analyzed for T2 distribution at elevated temperature and pressure. First the cores were saturated with formation brine to 100% Sw, followed by desaturation using the porous plate pressure equilibrium method to Swirr. Initially, desaturation with gas provided very low T2 cutoffs; desaturation steps were repeated using a lab oil with reservoir property to investigate its positive impact on the T2 cutoffs and to use in the NMR log domain.

The T2 curve of the fully saturated plugs with brine shows a shift towards the shorter T2 time. Determination of T2 cutoff from the gas-brine system in the laboratory results in lower T2 cutoff values approximately 15 to 50 msec. This is due to the lower T2 response at the Swirr state from the combined affect of pores still partially saturated with brine and gas diffusivity affects. When desaturating with lab oil, the NMR response results in more reliable T2 cut-off of 55 to 100 msec.

NMR T2 cutoff for BVI using the oil-brine system has been determined using two methods, a conventional method where T2 cutoff is determined where the cumulative T2 value of the Sw at 100% brine equals the cumulative T2 value of the Swirr. The other method is where the T2 cutoff separates major peaks of bound and free fluid in the incremental T2 response. The conventional method posed a challenge in picking correct T2 cutoff due to various complexity as outlined in the paper. The latter method provided more reliable and better control on picking T2 cutoff to apply in the NMR log domain.
Highly Sour Gas: The Best Options to Process it
Authors: Manuel Jacques , Damien Menet , Christian Bladanet
Published: November 2019

TechnipFMC was appointed by one its major client to conduct a feasibility study for the development a highly sour gas-condensate field. Sour gas levels are in the range of 22-28%vol of H2S and 13-17%vol of CO2 and contains also organic sulphur components such as carbonyl sulphide, mercaptans and disulphides.

The study addresses the evaluation of onshore technologies for gas and condensate processing (gas sweetening, gas dehydration, NGL recovery, condensate stabilization and sweetening) for five different set of export product: sales gas, LPGs, hydrocarbon condensates, Sulphur or re-injection of the acid gases, with the objective of selecting the most attractive scheme based on economic and HSE criteria.

Using this case study, this paper aims to present the methodology, the different process configuration screened, the pros and cons of each technology, and the influence of basic technico-economic parameters on the plant architecture and technology selection.
An Investigation of Pressure Buildup Tests in Bounded Reservoirs
Authors: Cobb William M. , Smith James T.
Published: November 2019

INTRODUCTION

One of the most important aspects of formation evaluation is the design, implementation, and interpretation of a pressure buildup test. Basically, this test requires that a producing well be shut in and that the associated change in bottom-hole pressure be measured as a function of shut-in time. Muskat1 introduced the first interpretation method for these pressure data to the petroleum industry in 1937, but for the most part, its significance was largely overlooked until the late 1940's. At that time, van Everdingen and Hurst2 revived new interest in transient pressure analysis with their classical paper on the behavior of unsteady-state fluid flow in a porous media.
Metagenomic next-generation sequencing for mixed pulmonary infection diagnosis
Authors: Wang Jiahui , Han Yelei , Feng Jing
Published: November 2019

Background: Metagenomic next-generation sequencing (mNGS) is emerging as a promising technique for pathogens detection. However, reports on the application of mNGS in mixed pulmonary infection remain scarce.Methods: From July 2018 to March 2019, 55 cases were enrolled in this retrospective analysis. Cases were classified into mixed pulmonary infection (36 [65.5%]) and non-mixed pulmonary infection (19 [34.5%]) according to primary diagnoses. The performances of mNGS and conventional test on mixed pulmonary infection diagnosis and pathogen identification were compared.Results: The sensitivity of mNGS in mixed pulmonary infection diagnose was much higher than that of conventional test (97.2％ vs 13.9％; P< 0.01) , but the specificity was the opposite (63.2％ vs 94.7％; P= 0.07) . The positive predictive value of mNGS was 83.3% (95% CI: 68.0-92.5%) , and the negative predictive value was 92.3% (95% CI: 62.1-99.6%) . A total of 5 (9.1%) cases were identified as mixed pulmonary infection by both conventional tests and mNGS, however, the pathogens identification results were consistent between these two methods in only 1(1.8%) case. In summary, the pathogens detected by mNGS in 3 (5.5%) cases were consistent with those by conventional test, and only 1(1.8%) case was mixed pulmonary infection. According to our data, mNGS had a broader spectrum for pathogen detection than conventional tests. In particular, application of mNGS improved the diagnosis of pulmonary fungal infections. Within the 55 cases, mNGS detected and identified fungi in 31 (56.4%) cases, of which only 10 (18.2%) cases were positive for the same fungi by conventional test. The most common pathogen detected was H uman cytomegalovirus in our study, which was identified in 19(34.5%) cases of mixed pulmonary infection . Human cytomegalovirus and Pneumocystis jirovecii, which were detected in 7(12.7%) cases, were the most common co-pathogens in the group of mixed pulmonary infection.Conclusions: mNGS is a promising technique to detect co-pathogens in mixed pulmonary infection, with potential benefits in speed and sensitivity.
Methicillin-resistant Staphylococcus aureus in veterinary professionals in 2017 in the Czech Republic
Authors: Neradova Katerina , Jakubu Vladislav , Pomorska Katarina , Zemlickova Helena
Published: November 2019

Background Cases of colonization or infection caused by Methicillin-resistant Staphylococcus aureus (MRSA) are frequently reported in people who work with animals, including veterinary personnel. The aim of this study was to determine the prevalence of MRSA colonization among veterinary professionals. A total of 134 nasal swabs from healthy attendees of a veterinary conference held in the Czech Republic were tested for presence of MRSA. The stains were further genotypically and phenotypically characterized. Results Nine isolated MRSA strains were characterized with sequence type (ST), spa type (t) and Staphylococcal Cassette Chromosome mec type. Five different genotypes were described, including ST398-t011-IV (n=5), ST398-t2330-IV (n=1), ST398-t034-V (n=1), ST225-t003-II (n=1) and ST4894-t011-IV (n=1). The carriage of the animal MRSA strain was confirmed in 8 cases, characteristics of one strain corresponded to the possible nosocomial origin. Among animal strains were described three spa types (t011, t034, t2330) belonging into one dominating clonal complex CC11. Conclusion According to our results, the prevalence of nasal carriage of MRSA in veterinary personnel is 6.72%. Although we described an increase compared to the results of previous study (year 2008), the prevalence in the Czech Republic is still remaining lower than reported from neighboring countries. Our results also indicate that healthcare - associated MRSA strains are still not spread among animals.
Ranking top-k trees in tree-based phylogenetic networks
Authors: Hayamizu Momoko , Makino Kazuhisa
Published: November 2019

'Tree-based' phylogenetic networks provide a mathematically-tractable model for representing reticulate evolution in biology. Such networks consist of an underlying 'support tree' together with arcs between the edges of this tree. However, a tree-based network can have several such support trees, and this leads to a variety of algorithmic problems that are relevant to the analysis of biological data. Recently, Hayamizu (arXiv:1811.05849 [math.CO]) proved a structure theorem for tree-based phylogenetic networks and obtained linear-time and linear-delay algorithms for many basic problems on support trees, such as counting, optimisation, and enumeration. In the present paper, we consider the following fundamental problem in statistical data analysis: given a tree-based phylogenetic network $N$ whose arcs are associated with probability, create the top-$k$ support tree ranking for $N$ by their likelihood values. We provide a linear-delay (and hence optimal) algorithm for the problem and thus reveal the interesting property of tree-based phylogenetic networks that ranking top-$k$ support trees is as computationally easy as picking $k$ arbitrary support trees.