bluuebunny/crossref_metadata_2025 huggingface dataset:
Fit-For-Service Qualification of Existing 13Cr Tubulars in Mildly Sour Wells Based on Thermodynamic Approach
Authors: Kumar Amit , Srivastava Manish , Al Shehhi Ali , Al Daghar Tariq , Abdulhai Walid , Gan Chee-Lam
Published: November 2018

Most of the existing wells in a giant oil offshore field in Abu Dhabi are equipped with L80-13Cr corrosion resistant alloy (CRA) tubulars to provide protection from CO2 corrosion due to sweet nature of reservoir. Recently, some of the wells are showing a presence of mild H2S due to unexpected reservoir souring or other geological changes. The presence of H2S in production fluids raises concerns about sulfide-stress-cracking (SSC) of L80-13Cr. As L80-13Cr CRA has been known to have limited SSC resistance, it is important to understand the maximum acceptable limit of H2S in production fluids for safe operation.

Industry standards such as ISO15156/ NACE MR0175 and NORSOK-M-001 recommend safe acceptable limits of H2S for 13Cr tubular materials based on the partial pressure of H2S. However, these approaches do not take into account the effect of temperature, or non-ideal gas behavior of H2S at high pressure. Pressure, temperature, salinity and pH in the wellbore impact the solubility and chemical behavior of H2S in the water phase which defines the corrosive environment to which the material is exposed. Therefore, it is important to include non-ideal gas and solution behaviors in order to define the acceptable limit of H2S for fitness-for-service (FFS) material evaluations.

In this work the acceptable limit of H2S in the wellbore was determined using a combination of thermodynamic modeling and field corrosion data. A molecular thermodynamics approach was used to calculate pH and dissolved H2S levels in water along the production tubing length. Shut-in and production operation scenarios were simulated to identify the worst-case scenario using thermal modeling software. Furthermore, tubing inspections were conducted using a multi-finger caliper tool to identify any corrosion damage. All of this information was used to identify the acceptable limit for H2S in the wellbore. This approach to determining acceptable H2S limits will avoid unnecessary workovers and enables cost saving through continued use of existing materials. Furthermore, it supports the development of a corrosion monitoring plan, and FFS assessment of tubulars based on the wellbore environment.
How Broadband, High Dense, Full Azimuth & Point Source Point Receiver Acquisition Improves Seismic Interpretation in Onshore Abu Dhabi
Authors: Al-Naqbi Sheikha , Elila Abusaa , Vargas Jose , Mahgoub Mohamed
Published: November 2018

Acquiring seismic data with S4 (Single Source, Single Sensor) is proven technology and it has many advantages over the conventional source and receiver array acquisition type. The array has an intra array statics issue when deployed on large elevation variation such as sand dunes and attenuating higher frequencies as well. S4 with denser spatial sampling with smaller shotline and receiver line spacing could jointly with seismic data broader bandwidth to improve interpreting many seismic details such faults, fractures, tiny stratigraphic features resolution. A debate was raised locally about the value of acquiring seismic data with S4, if only for the sake of acquiring seismic data with shorter time duration compare to the too much equipment needed for array acquisition type that consumes longer time in general. Alternatively, S4 really bring a real value of information and producing an outstanding seismic volume for amenable interpretation with confidence that will lead to utilize the seismic data to help in optimizing the well trajectories placement.

This high density broadband 3D seismic acquired survey with fully sampled wave-field data has used the latest acquisition and imaging technologies, it has delivered critical information that can help to reduce drilling risks and to support future 4D reservoir monitoring which improved signal to noise ratio when compared with legacy dataset.

An advance seismic processing workflow is tailored to improve the final image quality, and to preserve the azimuthal amplitude variation with offset and azimuth, which in turn can lead to the derivation of intrinsic rock property attributes for better reservoir characterization. A multi azimuth Prestack depth migration approach resolved most of the effects of heterogeneities in the shallow part and in the velocity field, which sometimes can be misinterpreted as azimuthal anisotropy.
Reducing Horizontal Hole Size from 8.5 to 6.75 Reduces Unconventional Well Construction Cost by 25%
Authors: Schumacker Eric David , Vogelsberg Philip
Published: November 2018

Slim hole well design can reduce well construction cost through a reduction in steel, fluids, and disposal costs. In the industry, there has been a misconception that slim hole size possesses the tradeoff of slower ROP and less efficient fracture treatment. Improvements in downhole tools, drill strings, rig capability, and drilling fluid design have been implemented to improve ROP in slim holes. Completions designs were refined for slimmer holes to avoid any significant loss in stimulation effectiveness and maintain well value. Through systematic replication of learnings and designs across basins, slim hole well design has advanced. Slim hole well design (transition from 8.5" / 7.875" hole and 5.5" production casing to 6.75" hole and 5.5" / 4.5" production casing) can reduce Unconventional well cost by over 25% which reduces well unit development cost (UDC).
Aging LNG Static Equipment Life Extension - A Case Study
Authors: Sabry Houssam
Published: November 2018

ADNOC LNG is a pioneer LNG and Gas Operator, Owner and Exporter. ADNOC LNG owns and operates three LNG Trains in addition to operating five Gas Processing and Export Trains.

ADNOC LNG operates its facilities from Das Island which is approximately 186Km Offshore Abu Dhabi. ADNOC LNG commissioned two of its three LNG trains in 1977. Third LNG train was commissioned in 1994. The design lifetime of all the trains is 30 years.

Trains 1 and 2 have gone through a life extension study to extend its lifetime from 2007 till 2019. Furthermore, recently another longevity study was concluded to increase the lifetime of Trains 1 and 2 till 2024. Further study is being conducted to further extend the design lifetime of the three LNG trains till 2040. This paper shares ADNOC LNG experience in terms of lifetime extension in terms of LNG static equipment reviews for assets life extension.

These life extension studies were done through an ADNOC LNG multidisciplinary team. The team reviewed the entire LNG facilities. Facilities were divided into the following systems: –Static Equipment–Safety Critical Equipment–Rotating Equipment–Civil and Structures–Electrical and Instrumentation

The static equipment assets life extension exercise started with data collection from all available static equipment integrity systems and tools. The following systems were used to extract data: –Inspection Management System – containing the entire inspection and maintenance records for static equipment–Risk Based Inspection (RBI) System–Risk Based Assessment (RBA) exercises–Focused Integrity Reviews–CMMS (SAP Records)–Root Cause Analysis (RCA) reports–Fitness for Service (FFS) exercise–Major Turn Around (TA) Reports

These data in terms of inspection and failure history, degradation rates, probability of failure and FFS results were all analysed to answer one question, which is whether these static equipment degradation rate would allow them to survive till 2040 and in case this is not possible then what would be the recommended actions, cost for these actions and its schedule. Hence a tecno-econimc evaluation for the recommendations was done.

In the paper ADNOC LNG will share the methodology of evaluation, share few cases in terms of longevity like the LNG storage tanks and export jetties in addition to key findings of the study.
Invisible Lost Time Initiative ILT in Drilling-Toward More Efficiency, High Performance and High Profitability-Do More with Less
Authors: Shamsi Juma Al , Nauimi Mouza Al , Hosani Faisal Al , Sairi Abdulrahman Al
Published: November 2018

Dropping of oil price has significant influence in Oil & Gas industry in term of cost saving. A lot of efforts and initiatives were made in order to sustain with the current situation and to facilitate the Oil and Gas industry to lead the market. Existing of alternative energy is another challenge which threats the market.

ILT initiative was introduced in the Drilling Function to Drill Wells in more efficiency and high performance considering the priority for safety and integrity. The main objective of ILT is to identify the area's of invisible lost time, track it and to Eliminate As Low As Possible (ALAP) and to Drill Well in Shortest Time compare it with Best Of Best Wells (BOB)

During the period when the oil price was high, a lot of expansion in terms of rigs and manpower were there, where there are no focus in the performance of the wells which lead to big inflation in well duration resulted by Non Production Time and Invisible Lost Time.

Invisible Lost Time is the hidden operation time which is lost due to many factors such as shortage of the key players, lack of experience, reluctant of people and shortage of proper equipment & tools.

All these factors are affecting the main drive mechanism in the well which is, the ROP, Tripping Speed and Connection Time. A clear road map for the project was set for three phases. Pilot Phase, where focus was on the mentioned areas and identify the gaps and lesson learns. 2nd Phase, where the gaps can be filled and the lesson learns can be applied to get more results. The Final Phase were can be implemented to all the rigs after Healthy Check were implemented in Phase I & Phase II.

This Paper will describe clearly the Objective of the ILT Project, The Key Elements of ILT; the Challenges were faced to achieve the Target, Case Study and Recommendation.
Detection of Stuck Pipe Early Signs and the Way Toward Automation
Authors: Alshaikh Abrar A. , Albassam Mohammed K. , Al Gharbi Salem H. , Al-Yami Abdullah S.
Published: November 2018

The earlier a stuck pipe incident is predicted and mitigated, the higher the chance of success in freeing the pipe or avoiding severe sticking in the first place. Time is crucial in such cases as an improper reaction to a stuck pipe incident can easily make it worse. In this work, a novel and practical model was developed using real-time drilling data to automatically detect leading signs of stuck pipe during drilling operations and communicate the observations and alerts, sufficiently ahead of time, to the rig crew for avoidance or remediation actions to be taken.

The model uses key drilling parameters to detect abnormal trends that are identified as leading signs to stuck pipe. The parameters and patterns used in building the system were identified from published literature and historical data and reports of stuck pipe incidents. The model is designed to be implemented in the real-time drilling data portal to provide an alarm system for all oil and gas rigs based on the observed abnormalities. The alarm is to be populated on the real-time environment and communicated to the rig crew in a timely manner to ensure optimal results, giving them more time to prevent or remediate a potential stuck pipe incident.

Testing the model on several wells showed promising results as anomalities were detected early in time before the actual stuck pipe incidents were reported. It further facilitated better understanding of the underlying physics principles and provided awareness of stuck pipe occurance. It improved monitoring and interpretating the drilling data streams. Beside such pipe signs, the model helped detecting signs of other impeding problems in the downhole conditions of the wellbore, the drilling equipment, and the sensors.

The model exceptionally uses the robustness of data-based along with the physics-based analysis of stuck pipe. This hybrid model has shown effective detection of the signs observed by experts ahead of time and has helped providing enhanced stuck pipe prediction and risk assessment.
Coupling Low Salinity Water Flooding and Steam Flooding for Heavy Oil in Sandstone Reservoirs; Low Salinity-Alternating-Steam Flooding LSASF: A Novel EOR Technique
Authors: Al-Saedi Hasan, N. , Flori Ralph E. , Mortadha Alsaba
Published: November 2018

Recently Al-Saedi and Flori et al. (2018a) studied the potential of low salinity alternating steam flooding (LSASF) in laboratory Berea sandstone cores and the results were promising for increasing heavy oil recovery. In this study, we applied the new LSASF method on oil-impregnated reservoir sandstone cores from the Bartlesville sandstone reservoir in eastern Kansas. These samples contain high viscous oil up to 600 cp.

Combining low salinity water (LS water) flooding and steam flooding is a novel idea which takes advantage of the relative strengths of both methods. LS water has been extensively studied by many researchers with promising results. Steamflooding is also much studied for applications particularly in heavy oil fields where recovery is increased by reducing the oil viscosity. The density difference between steam and heavy oil raises difficult problems in some reservoirs that can only be solved by injecting water with steam. In particular, those problems are gravity override, channeling, and early breakthrough.

In this study, numerous reservoir sandstone cores were retrieved from the Bartlesville sandstone reservoir and cleaned, dried, vacuumed, and saturated with formation water (FW) that was identical to the reservoir FW. The water was displaced with a heavy crude oil to achieve Swi, and pre–aged for five weeks at 90°C. These cores were then flooded with 2 PV FW and then followed by different cycles of LS water + steam. A variety of LS water salinities were used (d4FW, d8FW, and d40FW).

The laboratory experiments showed that optimum recovery is achieved by diluting the FW 40 times and using the same water in a shorter steam cycle. The oil recovery was 70.6% of the OOIP, which represents a quite high percentage of oil recovery in heavy oil reservoirs. The results of contact angle showed that the cores flooded using the novel LSASF were shifted to more water–wet conditions. Chemical analyses showed that using this novel LS water plus steam method improves recovery by enhancing the permeability of the rock, reducing precipitation caused by LS water flooding, and increasing dissolution of minerals which increased oil recovery. We also developed the LS water alternating steam flood in order to gather the benefits of LS water itself and to reduce oil viscosity by steam and prevent the aforementioned steam problems by using LS water.
Integrated Data Analytics and Visualization for Reservoir and Production Performance Management
Authors: Mohan Richard , Narayanan Ram , Al Yazeedi Haifa , Al Naqbi Tayba , Willems Maarten , Escorcia Alvaro , Saputelli Luigi , Abdulla Nada , Gioria Gian Marco
Published: November 2018

ADNOC operates its onshore and offshore fields through its operating companies. In order to effectively govern and steer the operations, it is essential for ADNOC to monitor, track and measure key reservoir and production performance indicators efficiently on time. In this regard, ADNOC Upstream has established an integrated reservoir and production performance visualization environment that enables upstream departments to efficiently monitor the performance of onshore and offshore operations at different levels from the headquarter in a collaborative manner with the operating companies.

The integrated visualization environment is built on four key components, the upstream data hub, visualization, process automation and data governance which forms the common foundation for various upstream projects, enabling multi-project collaboration, reporting integrity, common business data and KPI definitions. The datawall in Thamama Collaboration Center is powered by the integrated reservoir and production performance visualization dashboards configured on objective based themes such as Reservoir Management, Production Assurance, Business Plan Assurance and others required by different departments. The visualization capability is enabling engineers and managers in the upstream directorate, to monitor key reservoir and production performance information on a daily and periodic basis, and the solution facilitates collaborative review sessions with OPCO team either on a regular or adhoc manner and to initiate and track actions.

The integrated visualization environment shall be continuously enhanced to add more themes based on business needs, and to carry out advanced data analytics to predict and forecast performance leveraging the established foundation. Business processes shall be streamline through automation of the performance measurement processes to achieve higher degree of digital transformation.
Comparison of Steam Front Shape During Steam Flooding Process Under Varying Steam State Condition: Numerical Analysis
Authors: Sun Fengrui , Yao Yuedong , Li Guozhen , Li Xiangfang , Sun Jian
Published: November 2018

It has been reported that superheated steam can greatly increase the oil recovery efficiency. After superheated steam injection, the viscosity of heavy oil is greatly reduced. Besides, the permeability of the rock is increased. However, this previous works were focused on the chemical respects of oil displacement mechanisms by superheated steam injection. The difference in physical heat transfer between superheated steam and wet steam has not been revealed.

At present, there is a lack of study of its physical heating on the increase of productivity. In this paper, a numerical study is conducted to reveal the difference between superheated steam and wet steam during the steam flooding process. The contribution of physical heating on the productivity is studied.

Simulation result show that: (a) The effect of physical heating of superheated steam can be neglected. The contribution of chemical reactions of superheated steam with heavy oil and rock minerals is the dominant factors for oil recovery mechanisms under superheated steam injection. (b) When the temperature is higher, the pressure wave propagates more widely. However, the difference in pressure field between superheated steam and wet steam with a steam quality of 1.0 is negligible. (c) There exists severe steam fingering phenomenon under superheated steam injection. This is because the superheated steam is completely vaporized which greatly increases its percolation capacity.

This work sheds light on the contribution of physical heat transfer on temperature spread in reservoir under varying steam state during the steam flooding process. This work pointed out that the study of chemical reactions should be the research direction of the next step in oil displacement mechanisms by superheated steam injection.
Applying Automated Model Building to Predictive Maintenance in Oil and Gas
Authors: Herve Philippe , Moore Keith , Rosner Marla
Published: November 2018

Predictive maintenance has become a major focus for the largest industrial companies because of the value it derives, including reduced downtime, improved efficiency, reduced maintenance costs, and others. Success of predictive maintenance programs is achieved when data, analytics, and subject matter expertise intersect. While data and subject matter expertise are always available, analytics talent is often lacking or facing numerous challenges which hinders the success of predictive maintenance programs.

Automated model building (AMB) aims at delivering artificial intelligence to the fingertips of industrial companies and hence ensuring the success of predictive maintenance programs without the need of large data science organizations.

The automated model building platform ingests the operational (sensor) and failure/fault data and automatically builds AI models to predict the remaining useful life for the asset. The patented technology behind the platform drives feature engineering and model selection which allows customers to automatically create numerous new variables from the sensor data and tests thousands of different models. The platform will then select the optimal set of variables and the model that will achieve the best performance.

The entire process can be performed in a matter of few minutes without the need to know the details of all AI models. The platform also gives details on the selected models, which aids with interpretability.

This paper will discuss why automated model building and artificial intelligence are needed to deliver effective, scalable predictive maintenance to the oil and gas industry, as well as specific use cases in which AI-powered automated model building has been applied.
Characterization of the Pore System of Cretaceous Limestone Samples from Onshore UAE Field, Using Lab NMR, MICP, Petrography and Electrical Resistivity Measurements
Authors: Zakaria Hasan , Gomes Jorge
Published: November 2018

The use of Lab NMR, MICP, electrical resistivity measurements and conventional core analysis coupled with petrographic investigations, enabled the authors to understand the pore structure of several carbonate samples and establish a link between pore geometries, Archie's cementation exponent, capillary pressure behavior and NMR T2 response.

The lab work was performed on 68 carbonate plugs retrieved from 5 vertical wells completed on a Cretaceous carbonate reservoir, and located at different structural positions (from crest, mid-flank and down-flank areas), capturing different hydrocarbon column heights and, therefore, different degrees of diagenesis and porosity degradation. The equipment used was Magritek 2MHz NMR Rock Analyzer for the T2 distributions, Micromeretics for MICP, Pantera for the ambient resistivity measurements and PORG-200TM for the conventional core analysis. The petrography was done using conventional polarized light microscope.

From the combined analysis of NMR T2 spectrum and electrical resistivity measurements we concluded that the magnitude of the Archie's cementation exponent "m" is greater when the samples exhibit variability within the largest pore class ranges (meso to macro scale) than on the smaller pore class range (micro to meso scale). The bi-modality of the pore system tends to increase the cementation exponent "m". The results of this study also shed some light on the rate of porosity degradation with depth which was correlated with the amount of stylolitization (pressure solution) downflank.

The novelty of this work is the combined analysis of NMR, electrical resistivity and petrography on the assessment of the pore structure of limestone samples. The main finding of this work has direct application to the computation of water saturation models for rocks with dual porosity systems. If the understanding of the pore structure is not taken into consideration during petrophysical analysis, the volumes of hydrocarbons could be under/overestimated with consequences on the reserves assessment.
Producing from Residual Oil Zone ROZ: Concept and Strategy for Kuwait
Authors: Dhote Prashant Dhote , Al-Bahar Mohammad , Cole Anthony , Al-Sane Amal , Bora Anup , Sreenivasan Ashique
Published: November 2018

Residual Oil Zones (ROZs) are an area of incrasing attention from hydrocarbon E&P industry with ever depleting reserves in known oil accumulations and advent of Carbon Dioxide (CO2) Capture and Storage needs and technology. ROZ can serve as viable solution to both the future problems as a possible vast new oil resource and a prospect for reducing carbon emission. ROZs can be defined as thick pile of low-quality reservoir rock below traditional oil-water contact with about residual oil saturations of mainly irreducible oil resulting from the natural flushing of reservoir due to buoying forces and aquifer action in geological past in earlier oil-filled part of reservoir. The production of oil from ROZs from such reservoirs is technically and economicaly feasible through application of enhanced oil recovery techniques - largely through missible CO2 flooding/injection in the zone because of the nature of fluid and reservoir rock. The depostional and tectonic regime in the Kuwait Petroliferous Basins is investigated to demonstrate the occurrence of and independently assess ROZ potential. The understanding of Kuwait Petroliferous Basin indicates that ROZs might be developed by hydrodynamic actions associated with tectonic regime. The degradation of oil by water action and related increase of sulfur content of crude oil can be used as workable proxy for identification ROZ potential of the rerservoir. The regional mapping, understanding of tectionic history and regional systhesis of crude oil composition shows an extensive stratigraphic and lateral existence of ROZ potential across the Kuwait Petroliferous Basin.

This study aims to provide strategic roadmap and detail data acquisition program that will reveal ROZ production potential in Kuwait for Kuwait Oil Company (KOC).
Exploring for Wolfcamp Reservoirs, Eastern Shelf of the Permian Basin, USA, Using a Machine Learning Approach
Authors: Ribet Bruno de , Wang Peter , Meers Monte , Renick Howard , Creath Russ , McKee Ryan
Published: November 2018

Objectives/Scope

The objective was to leverage prestack and poststack seismic data in order to reconstruct 3D images of thin, discontinuous, oil-filled packstone pay facies of the Upper and Lower Wolfcamp formation (Sakmarian time: 293-296 Ma).

Methods, Procedures, Process

The well-to-seismic tie was carefully established using synthetic seismograms, which enabled the facies log to be properly associated with the corresponding seismic samples. The seismic data were all resampled from 2 ms to 0.5 ms in anticipation of being able to recover facies thicknesses on the order of 2 m. Six neural networks with diverse learning strategies were trained to recognize the nine facies classes in the high-resolution seismic stack: Instantaneous Frequency, Instantaneous Q Factor, Inversion (P-Impedance), Semblance, Dominant Frequency, Most Negative Curvature, and eight Angle Stacks, using a two-stage learning and voting process.

Results, Observations, Conclusions

At the wells, the nine facies were reconstructed from seismic at a 97% accuracy rate. The bootstrap classification rate, a proxy for blind well testing, was over 80%, which indicates a high-quality modeling process. The pay facies was described with no false positives or false negatives. In the 3D seismic volume between the wells, the procedure produced a Most Likely Facies volume (unsmoothed and smoothed), and nine individual Facies Probability volumes. The pay facies was visualized in a 3D voxel visualization canvas using opacity, and also in a two-way time thickness map. The usable vertical and horizontal resolution was much greater than that of the original seismic. Based on these classification results, additional drilling locations were chosen to further target the oil-filled packstones.

Novel/Additive Information

The classification results were created by neural networks, which can be used as a substitute for traditional AVO, inversion and cross-plotting techniques for seismic reservoir characterization. The time need to create the Machine Learning results for this small dataset was on the order of ten minutes.
Online Condition Monitoring System Identifies Developing Faults in Reciprocating Compressor at the Very Outset
Authors: Qureshi Fayyaz Karim , Bickmann Thorsten
Published: November 2018

Safety of personnel, assets and environment has been an essential priority for most operators and there has been an ever-increasing emphasis from EHS authorities to improve systems to be able to trip automatically and save assets from any catastrophic failures. Like any other critical equipment, an online monitoring and protection solution has become inevitable for reciprocating compressors to address this requirement.

Additionally, inclination of operators towards proactive maintenance strategies instead of conventional preventive maintenance practices has prompted the need of an online condition monitoring solution that can provide insights into the condition and performance of machines. Instead of overhauling reciprocating compressors every 18-24 months and replacing all components as part of preventive maintenance, systems are able to pinpoint any developing faults within machines at an early stage; helping operators to plan outages, to arrange optimized spares timely and replacing only failed components with minimal downtime; ultimately justifying return on investment (ROI).

API recommendations for protecting reciprocating compressors have developed over the years. In 2007, API 618 5th Edition was released where only crankcase/frame vibration was recognized as minimμm requirement for protecting reciprocating compressors from a vibration monitoring system's perspective. Then a series of failures on several reciprocating compressors globally influenced API 670 to include crosshead vibration to protection matrix in 2014. The advancements and enhancements in solutions did not end there. Continuous improvements in data acquisition systems and vigilant analysis have identified certain additional parameters equally significant to identify developing faults in running gear and have been found efficient in protecting machines before the faults turned into failures; piston rod peak-peak displacement being one of those.

This paper describes comprehensive instrumentation required for condition monitoring of reciprocating compressors and delineates through case histories, how system was able to pinpoint failing components at early stages consequently saving machines from catastrophic expensive failures.
Use of Miniaturized Sensors to Optimize Cleaning Operations for In-Line Inspection of a Subsea Pipeline
Authors: Di Lullo Alberto G. , Passucci Claudio , Hester Keith C. , Zaffaroni Raffaele , Reinhart Robert
Published: November 2018

Pipeline in-line inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12" offshore line, a significant amount of wax deposits was expected and a series hydro-mechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs.

Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool.

In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss.

The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to re-create the line elevation, profile with limited a priori information.
Measurement of Propane and Butane Diffusion into Heavy Oil using Microfluidics - Is Small Better?
Authors: Zhao Hongying , Pierobon Scott , Pettigrew Adam , Doan-Prevost Jacques , Garnier Olivier-Francois , de Haas Thomas
Published: November 2018

The high energy intensity of steam-based heavy oil extraction processes is leading the industry to investigate solvent-aided processes for heavy oil/bitumen recovery. The diffusion coefficient of solvent in heavy oil is a key parameter to determine how effective these processes are. Measuring the diffusion coefficient is challenging, especially at in-situ conditions, i.e., at elevated temperature and pressure. This paper presents a microfluidics-based method for measuring the diffusion coefficient of propane and butane, the most commonly used light hydrocarbons in solvent process, into heavy oil at high temperature and pressure conditions.

A silicon-glass microfluidic chip was designed and fabricated using the Deep Reactive Ion Etching (DRIE) and anodic bonding. The diffusion tests were performed at temperatures ranging from 20°C to 120°C and pressures up to 100 bar. Upon blue light excitation, heavy oil naturally fluoresces at visible wavelengths, and the intensity varies with solvent concentration. Based on this mechanism, the light intensity change of the heavy oil in a 100-micron channel was recorded with a camera connected to the microscope during the diffusion process. An image processing method was developed accordingly to create a map of fluorescence light intensity versus diffusion time and distance, which was further processed numerically to calculate the diffusion coefficient with measured correlations between light intensity and solvent concentration.

At all testing conditions both solvents were liquid which inevitably would cause asphaltene precipitation at oil-solvent interface as demonstrated by the observations during the diffusion tests. It was also found that the asphaltene precipitation phenomena were more pronounced with butane than propane. To measure the diffusion coefficient, a method using solvent diluted oil was developed to avoid the asphaltene precipitation issue.

The measured diffusion coefficient of propane was around 0.6 × 10-10 m2/s using pure solvent method, and that of butane was in the range of 1—9 × 10-9 m2/s, at their corresponding testing conditions. For both solvents the diffusion coefficients increased with temperature while no satisfactory trend was observed with pressure within 100 bar.
Automatic History Matching Theory, Implementation, and Field Applications
Authors: Arroyo Negrete Elkin , Rodiguez Jose , Goryachev Sergey , Belova Natela , Al Blooshi Ahmed , Basioni Mahmoud
Published: November 2018

History matching (HM) is a mandatory step for any reservoir simulation study. Without a proper history match, a reservoir simulation model may lose credibility, or even worse, may lead to erroneous conclusions. HM is typically approached by reservoir enginners (RE) using a trial and error method, but there is a new, more advanced methodology known as computer assisted or automatic automatic history matching. Although assisted HM technology is well developed, its acceptance in the RE community has been slow. This paper aims to explain the concepts in a simple manner and suggest practical tips to make it easier for a practitioner to use automatic HM technology properly.
First Nitrified Managed Pressure Drilling Application in United Arab Emirates
Authors: Almetayev Rakhat , Al Hosani Muna , Al Ameri Saleh , Al Mutawa Ahmed , Ahmad Hussain Mushtaq , Abraham Jobin , Saleh Mujahed , Hadj-moussa Ayoub , Pham Dang Le Khoa
Published: November 2018

Drilling fluid losses while drilling a mature cretaceous limestone reservoir unit (Formation A) has been worsening over years with reservoir depletion and lack of pressure support. New drilling methods were needed to eliminate or reduce total losses and the associated non-productive time with them. Nitrified Managed Pressure Drilling proposed to help in mitigating losses and reducing non-productive-time. This paper explains the challenge, details the solution that was proposed to tackle, and discusses the results of the application.

Nitrified Managed Pressure Drilling (MPD) decreases the Equivalent Circulation Density (ECD) below the lowest possible static mud weight (water) and at the same time deals safely with any unintended hydrocarbon influxes while drilling the reservoir 6″ hole section. The well data was analysed and modelled with different Nitrogen pumping rates and Surface Back Pressure (SBP) to determine the best rates that a mitigates losses but at the same time prevent hydrocarbon influxes. A closed-Loop drilling system proposed utilizing rotating control device, a separation package, and locally produced membrane Nitrogen allowed to manage the annular hydraulic pressure profile accordingly and mitigate the total losses scenario eliminating the wait on water time

Rigorous planning and disciplined execution have led to safe and successful conclusion with no QHSE issues encountered. The designed Nitrified Managed Pressure Drilling solution succeeded in preventing the drilling fluid losses in the reservoir section by reducing the overbalance pressure of the drilling mud from 700 psi to 250 psi, which resulted in the elimination of 3 days of the rig's non-productive-time related to waiting on water. The closed-loop system coupled with a precise data acquisition and monitoring system has helped in maintaining a slight overbalance condition over the reservoir preventing any unintended hydrocarbon influxes to the surface. The lessons learned captured from this operation have contributed to the optimization of the Nitrified MPD in (Formation A) and to the overall MPD implementation in ADNOC fields.

This paper displays the first application of nitrified managed pressure drilling in the United Arab Emirates. The equipment design and planning have accounted for many different scenarios, as this type of drilling technology enables more precise wellbore pressure management with less interruptions to drilling ahead
Experimental Investigation over Effect of Geometrical Changes on Gas/Liquid Cylindrical Cyclone GLCC Separator
Authors: Asaadian Hamidreza , Soltani Soulgani Bahram , Rezaei Gomari Sina , Soltani Soulgani Bahador
Published: November 2018

Gas and liquid outlets length Study and its effect on Gas/liquid Cylindrical Cyclone (GLCC) separator performance. Gas body column length Study and its effect on GLCC separator performance. Inlet diameter Study and its effect on GLCC separator performance. Study of body column diameter and its effect on GLCC separator performance. Study of gas and liquid outlets diameter and its effect on GLCC separator performance.

An experimental GLCC separator was designed and built in laboratory to determine its domain. The best operational domain is where the equilibrium liquid level placed below the inlet and between 1 L/D and 3 L/D of separator column. If it pass the inlet it causes liquid carry over and if it settles below the 3 L/D it creates gas carry under in the separator. Thus the equilibrium liquid level was measured for different range of liquid and gas flowrates. In this work the gas superficial velocity was set between 0.3 and 6 meter per second and for each gas superficial velocity, liquid superficial velocity was from 0.3 to 3.3 meter per second. Moreover, different parts of test separator was changed and their effects on the separator operating domain was studied. These changes are 12.7 mm reduction in inlet diameter size, 5 mm reduction in liquid outlet diameter size, 5 mm reduction in gas outlet diameter size, 0.12 meter reduction in gas column length, 25.4 mm reduction in column diameter size and 1.4 meter increment in outlet length.

Based on this work the following results were obtained:Reducing the inlet diameter improves the GLCC separator performance. It allows more gas and liquid flowrates enter the separator for total separation by enhancing the centrifugal effect on liquid and gas phases.Reducing the liquid outlet diameter has negative effect in GLCC flowrates domain but this reduction can be used to control the equilibrium liquid level by a gate valve in liquid outlet leg.Reducing the gas outlet diameter has negative effect on GLCC performance. But in some situations controlling the amount of accumulated gas in GLCC can avoid liquid carry over in the system.Reduction in gas column length shows no effect on the separator flowrates domain.Increasing in length of outlet legs increases the friction force and limited the separator performance.Reduction in separator body diameter raises the chance of liquid carry over and gas carry under and has negative effect on flowrates domain.

These findings from GLCC performance give the main guideline to design more efficient separator design for oil and gas fields. Proper designing makes separator performance domain wider whereas it creates separators more compact which in turn minimizes the cost of construction accordingly.
Characterising and Defining Stimulation Zones in Tight Formations for Appraisal Wells Onshore U.A.E with the Aid of Integrated Standard and Novel Stress Determination Methods
Authors: Doucette Neil , Ziller Matthias , Addis Tony
Published: November 2018

Several onshore concessions, currently under exploration by ADNOC, consist of tight laterally variable reservoirs that pose a significant challenge during the evaluation phase of exploration.

Most tight hydrocarbon-bearing formations require fracture stimulation. As such, the evaluation phase of these resources comprises not only the characterisation of reservoir rock properties using petrophysical analysis but, crucially, the construction of 1-D Mechanical Earth Models which underpin the identification of stimulation intervals for both vertical and horizontal well completions. The 1-D MEMs discussed here were provided by different vendors and have been calibrated against interval pressure tests, that included standard "wet" straddle packer microfractures and novel "dry" Sleeve-Fracture tests. The microfracture test data used to calibrate the MEMs were obtained from different depth intervals in onshore Abu Dhabi E&A wells and exhibit non-ideal pressure decline "shut-in" behavior. This required re-analysis using different interpretation methods to identify the lower bound fracture closure pressures and minimum stress magnitudes.

The identification of stimulation intervals from the 1-D MEMs highlighted the uncertainty in the minimum stress magnitude estimations from both the log-based models, and the microfrac interpretations. The uncertainty in the log-based minimum horizontal stresses can exceed 0.15 psi/ft (>17%), even after calibration with the microfracture tests. The uncertainty in the fracture closure pressure obtained from the microfracture test can also be as large as 1,600 psi (0.22 psi/ft and 30%).

The identification of the sources of the uncertainty, their quantification and the re-evaluation of microfracture tests fed directly into updated 1-D MEMs, which led to improved recommendations for optimised injectivity tests and acid fracturing treatments. This, in turn, has translated into a successful fluid sampling and production appraisal programme.
Tailored 9 5/8–in. x 12 1/4-in. Single Piece Centralizer with High Restoring Force for Challenging ERD Wells in UAE
Authors: Bermudez Alvarado Romulo , Navas Luis , Mahamat Habib Abdelkerim Doutoum , Al Katheeri Yousif , Krieger Sebastian , Kiess Christian , Farley Douglas , Mostafa Khamis , Shaker Sherif , Khallaf Ahmed , Rajadhyaksha Sachin
Published: November 2018

This paper describes how the unique centralizer requirements for extended reach drilling (ERD) wells can be attained. By continuously evaluating past casing runs in combination with engineering input, the learning curve led from a standard centralizer to a highly customized solution. The necessary flow path target to enhance the wellbore isolation through cement placement is met by achieving the right centralizer performance and placing.

A single-piece high-restoring-force centralizer is the best solution for the high inclination well profile to obtain the required 9 5/8-in. casing stand-off for ERD wells.

The original centralizer design experienced challenges such as high doglegs in some of the longest 9 5/8-in. casing strings that have been run in the UAE to date. Customize the centralizers for different well profiles was necessary. They were developed and tested according to the latest API 10D (2001) specifications using precision equipment to ensure reliable test results that enable accurate hook load and stand-off simulation.

Initially, a standard off-the-shelf design of a 9 5/8-in. x 12 1/4-in. single-piece centralizer was used in two wells with the following results:Friction factor exceeded the expected values across the interval on occasion.Total Depth (TD) was sucessfully reached by washing down to bottom.Good centralization as per software design was attained (tageting 80%) with moderate to good isolation.

Due to the performance, while running in the hole (RIH), concerns arose due to the unexpectedly high friction factor which, could lead to difficulties RIH and reaching TD in future wells. The modified centralizer design has led to the following improvements:Reduction of friction factor to an average of 0.24 due to a significant decrease in the centralizer running force even through reduced hole diameter intervals and the high dogleg severities (DLS)Reaching TD successfully.Stand-off remained around 80%, as demonstrated by outstanding cement bond log results across the critical sections.

It is important to consider that this centralizer was designed not to lose any performance after being run through reduced hole diameter intervals. The application of enhanced centralization design (i.e., standoff >80%) ensured good quality of the cement job.
Soft Computation Application: Utilizing Artificial Neural Network to Predict the Fluid Rate and Bottom Hole Flowing Pressure for Gas-lifted Oil Wells
Authors: Bahaa Mazen , Shokir Eissa , Mahgoub Ismail
Published: November 2018

The fluid rates and bottom-hole flowing pressure of the wells are essential parameters in the petroleum industry. The need of accurate readings of these measurements are necessary for many calculations such as gas-lift optimization, field monitoring and depletion plans. Predicting these parameters without running in hole has a good impact on reducing the intervention risk and on organization financials by saving time and money. Huge number of correlations are used to estimate these parameters. These correlations need the values of different parameters that are not accurately found. Therefore, an artificial neural network (ANN) model was built from exported data set of PROSPER1 software, production logging tool (PLT), and test separator data. The ANN model was trained and tested by the PROSPER1 extracted data. Then, a number of test points gathered from the PLT reports validated the ANN model. The developed ANN model results in an accurate prediction of the well flowing bottom-hole pressure and well fluid rate. These readings of each well are used to build an integrated production model (IPM) using GAP2 software to apply different gas-lift optimization scenarios.