bluuebunny/crossref_metadata_2025 huggingface dataset:
Quantitative Seismic Interpretation Workflow for Sweet Spot Identification in Organic-Rich Mudrocks
Authors: Al Ibrahim Mustafa A. , Mukerji Tapan , Hosford Scheirer Allegra
Published: November 2019

Estimating the lateral heterogeneity of geochemical properties of organic rich mudrocks is important for unconventional resource plays. Mature regions can rely on abundant well data to build empirical relationships and on traditional geostatistical methods to estimate properties between wells. However, well penetration in emerging plays are sparse and so these methods will not yield good results. In this case, quantitative seismic interpretation (QSI) might be helpful in estimating the desired properties. In this study, we use QSI based on a rock physics template in estimating the uncertainty of the geochemical properties of organic mudrocks of the Shublik Formation, North Slope, Alaska. A rock physics template incorporating lithology, pore fraction, kerogen fraction, and thermal maturity is constructed and validated using well data. The template clearly shows that the inversion problem is non-unique. Inverted impedances cubes are estimated from three seismic angle gathers (near with angles between 0° and 15°, mid with angle gathers between 15° and 30°, and far with angle gathers between 30° and 45°). The inversion is done using a model-based implementation with an initial earth model derived from the seismic velocity model used in the processing phase. By combining the rock physics template and the results of seismic inversion, multiple realizations of total organic content (TOC), matrix porosity, and brittleness index are generated. These parameters can be used for sweet spot detection. Lithological results can also be used as an input for basin and petroleum system modeling.
Implementation of Tatweer’s Spatial Data Infrastructure and Utilization of Uav’s for Day-to-day Operations in the Bahrain Field
Authors: Nooraldeen Yasser , Puripanda Naresh , Bandla Kranthi , Derbas Zainab , AlNowakhda Ali
Published: November 2019

Tatweer Petroleum adopted the best GIS practices when implementing Tatweer’s Spatial Data Infrastructure and utilizing Unmanned Aerial Vehicles (UAV) for day-to-day Operations in the Bahrain Oil Field.

The initial milestone of the project was to have a detailed geospatial survey of the entire Bahrain Field, which was completed and introduced as the first "As-Built Geo-Spatial Map" of the Bahrain Field since the first oil well drilled in 1932. This allowed us to develop and deliver reliable GIS solution that eliminated conflicts and overlaps between projects, facilitating user acceptance. This led to the introduction of the concept of Spatial Data Infrastructure at an organizational level, which empowered the company with open access to high precision and up-to-date GIS services.

Following the SDI project and As-Built GeoSpatial Map, the GIS team is leading the initiative in utilizing Unmanned Aerial Vehicles (UAV), also known as Drones, to address the unique needs of the daily operations by providing safe, efficient, and cost-effective maintenance and inspection solution. Surveying and mapping is time-consuming, difficult, and often dangerous. UAV’s are used to allow surveyors and mappers to collect unlimited aerial data with precise measurements, while saving time, money, and manpower. They provide premium processing and analytic capabilities to support critical processes such as volume measurements, terrain mapping, site planning, etc. The survey data produces highly accurate, best-in-class orthophotos and Digital Elevation Models (DEMs).

This paper demonstrates the process of creating the first "As-Built Geo-Spatial Map" for the Bahrain Field, building Spatial Data Infrastructure, and utilizing Drone technology for day-to-day operations.
Geomechanical Assessment of Compaction Related Well Integrity Risks For A Large Field In Sultanate Of Oman
Authors: AL-Aamri Mohammed , Mahajan Sandeep , Mukhaini Hamed
Published: November 2019

One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction.

The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure

In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure.

The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment
Human Factors and Performance: Reducing Errors and Improving Safety
Authors: Khan Salman , Yaqoob Shamrose
Published: November 2019

Companies employ a variety of tactics to reduce workplace incidents. However, behavioral-based programs have proven highly effective because safety becomes a collective responsibility shared by all employees. This paper will focus on one such program, called Human Performance (HuP). Key facets of the program include safety training, raising awareness of employees’ susceptibility to human error, and informing them how to design management systems as well as to promote behaviors to prevent safety incidents.

People bring to their job their own personal mix of skills, knowledge, experience, attitudes, motivation, habits, and personality. These individual characteristics influence behavior in complex and significant ways. Through training, employees can recognize where errors occur and use the proper tools to change their habits and reduce injuries or quality errors.

The novelty of this approach is to empower workers to contribute equally to their own safety and operational excellence, rather than relying on written policies. The efforts focus on safety within and outside the company.
Gas Development and Monetization via Floating Facilities FLNG, FCNG, FGTL and FSRU
Authors: Yussoff Ir. Ikhwan
Published: November 2019

The PETRONAS Floating LNG concept was envisaged to monetize stranded gas resources. At the same time, PETRONAS has also exploring the development of Floating Compressed Natural Gas (FCNG) and Floating Gas to Liquids (FGTL) as part of the "Technology Challenge Initiatives". In completing the elements in the overall LNG value chain, an FSRU will also become one of the fast track method to import LNG especially to the non-LNG importer country.

The two floaters namely PFLNG1 & PFLNG2 was built by PETRONAS to monetize the gas for offshore Sarawak and Sabah respectively which in turn increased the country's LNG production capacity. As part of the aim to commit to green house or flaring mitigation, PETRONAS is also gearing up towards the evaluations of miniscale Floating CNG vs Floating GTL. On the supply side, the development of Floating Storage Regasification Unit (FSRU) is believed to be an added value to PETRONAS as one of the biggest LNG exporter in the world.

The fast track nature of the project presents a challenge to the Gas and Upstream Business in meeting the target date. The advantages of having a floating facilities as a solution to monetize the stranded gas field and mitigating the flaring/ venting activities will be covered considering the risk identified throughout the development phases. The important of front end engineering has led to a fit for purpose design and excellent construction methodology.

The famous debate with regards to offshore vs onshore gas development will be revisited aligned with the technology maturity and market availability. Speaker will review the new facilities as a viable option in the future for any gas developments requiring a quick solution. Extensive technology selection exercises were conducted in finalizing the turret mooring, gas treating, liquefaction, regasification, cargo containment and offloading systems.

Designers and licensors have done rigorous design optimisation and marinization studies on impact of floater motion where it was evaluated against an extensive list of criterias. Specific offshore and marine technology selection for the facilities will be discussed in the effort of realizing the aim to bring conventional gas facilities to offshore environment. Speaker will share the challenges in selecting the right equipments in order to suit the condition including sea state, weather and regulatory requirements.
New Integrated Analytical Approach for Multiphase Inflow Performance Relationship
Authors: Al-Rbeawi Salam
Published: November 2019

This paper introduces an analytical approach for generating the inflow performance relationships (IPR) of different reservoirs depleted by different wellbore types at different conditions. The main focus of this paper is given to multiphase flow (oil, gas, water) and two-phase flow (oil, gas) during transient and pseudo-steady state flow conditions. The proposed approach presents new integrated models for the IPR that correlates the wellbore pressure with the multiphase total flow rate or the normalized pressure and rate by the bubble point pressure and single-phase flow rate at this pressure. These models consider the changes in reservoir fluid physical properties and reservoir relative permeabilities by coupling PVT data and relative permeability curves. The motivation of this study is reducing the uncertainty in the IPR of reservoirs undergoing the multiphase flow.

Predicting multiphase IPRs may go throughout three tasks. The first is developing the pressure functions of reservoir mobility and total compressibility by developing several correlations for reservoir fluid properties such as oil, gas, and water formation volume factor as well as gas solubility in oil and water. Several correlations are needed also for relative permeability behavior of the three fluids with the pressure. These correlations can be generated by the multi-regression analysis of PVT data and relative permeability curves. The second represents developing the analytical models for the flow regimes that could be developed during the entire production life of the reservoirs. The single and multiphase flow IPRs for different flow regimes are predicted in the third task. The proposed IPR in this study is plotted between the wellbore pressure and the total flow rate at reservoir condition or the normalized reservoir pressure and flow rate.

The observations obtained from this study are: 1) The proposed approach for the multiphase flow IPRs is not only time-variant but also depends on the flow condition whether transient or pseudo-steady state flow. 2) The IPR of the multiphase flow gives lower performance than the single-phase flow. 3) The IPR of the early time transient production is better than the late time pseudo-steady state production. 4) It is highly recommended to develop the models of fluid properties for each reservoir instead of using the models presented in the literature.

The novel points presented in this paper are: 1) Introducing a new approach for the inflow performance relationships in the reservoirs experiencing multiphase flow and depleted by horizontal wells or multiple hydraulic fractures. 2) Introducing the pressure functions of the multiphase flow reservoir mobility and multiphase flow total reservoir compressibility that consider the changes in reservoir fluid properties and relative permeabilities with production time and pressure in constructing the IPRs.
Miscible Gas Injection in Heterogeneous Carbonate Reservoirs with Extensive Baffles
Authors: Wei Chenji , Wang Yuhe , Li Baozhu , Zhang Jingjian , Zhang Wan , Wu Jin
Published: November 2019

Miscible gas displacement is a promising enhanced oil recovery method in carbonate reservoirs technologically and economically. Though miscibility can be well understood using core-scale experimental and numerical models, the miscible displacement process in complex heterogeneous and multi-dimensional carbonate reservoirs is more complicated and needs further analysis. In this paper, we present our effort in probing the miscible gas displacement characteristics in a carbonate reservoir with baffles based on data from a real field.

Using compositional modeling, we evaluate miscible gas injection process in heterogeneous carbonate reservoir with baffles. Together with the detailed miscible front development in specific parts of the reservoir, the analysis also takes advantage of gravity stabilization realized by implementing the corresponding injector-producer pattern.

This paper presents an analysis of miscible gas displacement process, which can be considered as an extension from a simple one-dimensional model to more complex heterogeneous and multi-dimensional system. Using data from a real carbonate reservoir with baffles, we analyze the CO2 injection for the drive processes. The analysis is combined with the consideration of the effects of baffles and wettability. Mainly due to the multi-dimensional flow, our results show that the minimum miscibility pressure is higher than one-dimensional system. Besides, our results indicate gravity stabilization could be well maintained by proper injector-producer pattern. We also report the sensitivity analysis for wettability changes in carbonates.

This paper offers a study to analyze and evaluate miscible gas flooding process in heterogeneous carbonate reservoirs. Using a real case data, the study can help reservoir engineers to better design miscible gas flooding for other similar situations.
Machine Learning Approach to Classify Water Cut Measurements using DAS Fiber Optic Data
Authors: Alkhalaf Muqbil , Hveding Frode , Arsalan Muhmmad
Published: November 2019

A crucial part of optimizing well production is accurate flow metering for both onshore and offshore environments. The industry currently relies on test separators and multiphase meters. These methods have limitations in terms of cost, transportation and safety. In this paper, an alternative method to classify water cut measurement in oil wells based on Distributed Acoustic Sensing (DAS) data and machine learning will be discussed. Fiber optics is an effective tool to perform downhole logging, however, the challenge usually resides in the analysis and processing of the logged data. After performing a flowing survey on an oil well a dataset was developed using the logged DAS data in combination with production logging tool (PLT) measurements. After extraction, processing and labeling the raw DAS data, this dataset is used for training supervised machine learning models.

In this paper, different classical machine learning models to train this dataset is assessed in terms of accuracy, speed and training/testing segments. The data gathered from the PLT shows a limitation in the variation of water cut percentages between the zones ranging from 71% to 76%. This limits our ability to assess the validity of the model, risk of overfitting, since most points share a similar target value. This is also reflected on the Rayleigh backscatter collected by the laser box where samples from different production zones share a similar value distribution across most frequency ranges. Three different classification machine learning models were selected simple Decision Tree and two ensemble method models—adaptive boost and Random Forest. The ensemble method models offer a parallel and sequential training schemes that increases the variance and reduce the bias in the model. After splitting and shuffling the data, were 10% of the original data was used for training, all models were trained in different percentages of the training set. Multiple metrics were chosen to assess the model's performance including accuracy, F-score and confusion matrices. Random forest classifier appears to be the best choice for this challenge, with a maximum accuracy of 98% and F-score of 0.99. The models show high dependency on low frequencies—lower than 500 Hz—where value distribution across production zones in DAS measurements is comparatively higher. Both ensemble method models are less bias with a maximum feature weight of about 0.1, in contrast, the simple Decision Tree model was highly dependent on a single frequency response. In future work, a more complex and diverse dataset will be collected from wells with a wider range of variances in terms of conditions and types. Moreover, after creating a more robust dataset alternative approaches can be assessed both classical machine learning models—regression and classification—and deep learning.
Integrated Reservoir Characterisation of an Emerging Unconventional Resource Play in the UAE
Authors: Newby Warren , Abbassi Soumaya , Fialips Claire , D.M. Gauthier Bertrand , Padin Anton , Pourpak Hamid , Taubert Samuel
Published: November 2019

The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its age-equivalent Najhma shale member in Kuwait.

The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment.

Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays’ productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
Use Of Tracer Technology to Improve Reservoir Understanding
Authors: Al Agbari Zainah , Chatterjee Monalisa , Hewitt Paul , Mohamed Ihab , Sudarev Maxim , Latypov Eduard , Al Bairaq Ahmed , Al Amri Ammar
Published: November 2019

Using a tracer as a monitoring technique to measure the migration of the injected fluid in the reservoir is relatively inexpensive method, and it applied in numerous fields throughout the world. The application of tracer can assess the volumetric sweep to quantify the amount of fluid flowing from injectors to producers. It gives an indication of offending injectors. Tracer helps in addressing the communication between different reservoir units. Another objective is delineation of flow barriers to identify the geological features that dominate the flow directionality (i.e. high permeability streaks, faults, fractures, etc) to determine directional permeability trends. The information obtained from tracer can reduce the model uncertainty and provide better tuning for future prediction.

The tracer data is used to generate not only qualitative information but also a substantial amount of quantitative data. Primarily, chemical tracers should be tested against a number of reservoir formation rocks and found not to adsorb or retard. Tracers are injected in the injectors and the samples are collected from nearby producers. Analysis of tracer concentration versus time curves from individual producing wells enables interwell flow characteristics to be determined so that improvements can be made to optimize sweep effectiveness of the hydrocarbon reserve. A record of base line sampling and analyses from all producers should be conducted. A frequent sampling and analysis are performed to understand the reservoir characteristics and performance.

After the application of tracer technique, the following results were observed: The first breakthrough was detected after about one year; due to the short distance between the injector and the producer. The second breakthrough was detected after about three years; due to the reservoir characteristic in the producers. An identical patterns of tracer response was seen, indicates almost homogenous reservoir in the tracer injected. This points out towards a similar depositional pattern across the reservoir. Most of tracers are observed downward towards the flank area. Tracer direction was to the least pressure area (flank) due to high offtake. No breakthrough was observed in the attic wells due to high pressure area.

Tracer technology is inexpensive method used to provide inflow directional information, and it has no impact on the completion design and effectively prove the reservoir characterizations and well performance.
Modelling of Permeability and Strain Evolution in Chemical Creep Compaction Experiments with Fractured and Unfractured Chalk Cores Conducted at Reservoir Conditions
Authors: Kallesten Emanuela , Østebø Andersen Pål , Berawala Dhruvit Satishchandra , Korsnes Reidar Inge , Vadla Madland Merete , Omdal Edvard , Zimmermann Udo
Published: November 2019

Understanding the impact of typical water-related IOR techniques is fundamental to the development of chalk reservoirs on the Norwegian Continental Shelf (NCS). We investigate the contribution and interplay of key parameters influencing the reservoir's flow and storativity properties such as effective stresses, injecting fluid chemistry and geomechanical deformation. This is done by developing a mathematical model which is applied to systematically interpret experimental data. The gained understanding is useful for improved prediction of permeability development during field life.

The model we present is for a fracture chalk core where fluids can flow through the matrix and fracture domains in parallell. The core is subject to a constant effective stress above yield resulting in time-dependent compaction (creep) of the matrix, while the fracture does not compact. Reactive brine injection causes enhanced compaction, but also permeability alteration. This again causes a redistribution of injected flow between the two domains.

A previous version of the model parameterizing the relation between chemistry and compaction is here extended to quantify the impact on permeability and see the impact of flow in a fracture-matrix geometry. A vast set of experimental data was used to quantify the relations in the model and demonstrate its usefulness to interpret experimental data. Two outcrop chalk types (Aalborg and Liege) being tested at 130 °C and various concentrations of Ca-Mg-Na-Cl brines are considered. However, assumptions were required especially regarding the fractures behavior since directly representative data were not available.

The tests with inert injecting brine were used to quantify the impact of matrix and fracture mechanical compaction on permeability trends. To be able to explain the tests with reactive brine, an important finding is that permeability not only decreased due to enhanced porosity reduction, but also because of a quantifiable chemistry related process (dissolution-precipitation).

Sensitivity analyses were performed regarding varying fracture width, injection rate and chemistry concentration to evaluate the impact on chemical creep compaction and permeability evolution in fractured cores. The model can be used to highlight parameters with great influence on the experimental results. An accurate quantification of such parameters will contribute to refining lab experiments and will provide valuable data for upscaling and field application.
Challenges Faced in Design & Selection of Umbilical for Offshore Facilities
Authors: Kumar Naresh , Paul Raju , R.Kamal Faris , Takieddine Oussama
Published: November 2019

The present trend is to use the umbilical for transmitting electrical power, instrumentation signals and to transport fluids & gas in one assembly over long distance to the Offshore Oil and Gas facilities. The installation of power generation facilities at offshore platforms is not a preferred option due to space constraints and the huge installation and running cost. Hence, the electrical power is transmitted from onshore generation facilities to offshore facilities by composite subsea cables.

Similarly for example the cost of installing corrosion inhibitor package at offshore facilities is huge considering the space occupied by the package skid which in turn increases the structural cost. The electricity required to run the corrosion inhibitor pump motor and other auxiliaries will result in higher power demand and subsequently the higher installation and operation cost. Hence, it is economical to transfer the corrosion inhibitor from nearby onshore facilities to offshore facilities by using instrumentation tubes, pipes and hoses.

The use of umbilical which houses the composite subsea cable and tubes carrying fluids/gases in one assembly result in substantial cost savings in terms of installation, transportation and laying cost. The housing of submarine composite cable with tubes in one assembly poses many challenges for the design and selection of umbilical. This paper provides comprehensive ideas about design, testing and selection of umbilical, the challenges faced and the way forward to overcome the challenges in selection of umbilical.
Successful System Schedule Integration for a Complex Multi Package Mega Project
Authors: Saat Sahaiza
Published: November 2019

The Pengerang Integrated Complex (PIC) is a US$27b multi package fast-tracked mega project with execution period of 60 months to ‘Ready for Start-up’ in Q1 2019. One of the largest project of its kind in the world constructed at a single time and location, PIC consists of a Refinery and Petrochemical Integrated Development (RAPID) and supporting facilities. A successful integrated system schedule was established towards achieving on-time project completion by early 2019.

The key challenges lie in the immense complexity of the project with involvement of over 140 organizations including more than 40 EPCC packages, supported by 13 licensors and over 200 suppliers and Contractors, around 250k EPCC schedule line items and alignment of 117 Integrated Networks across over 30 main process units. To drive a successful system schedule integration, three key guiding principles were followed: a pre-emptive schedule management guideline for systemization and start-up sequence, integrated critical path schedule alignment engagements with EPCC Contractors and a lean task force collaboration by project planning and operation on prioritized critical utilities delivery for EPCC commissioning activities.

As a result of the successful system schedule alignment and integration, the critical utilities i.e. power, steam, cooling water, fuel gas and fire water, were successfully delivered in quick successions according to the respective EPCC packages needs, allowing commissioning activities within the packages and the Integrated Networks crossing over multiple EPCC packages. The cohesive pre-commissioning, commissioning and start-up schedule between all EPCC packages propelled PIC project to a momentous "Finish Strong".

The critical success factor comprising of early creation of special task force driven by project planning and operation personnel in managing system schedule prioritization and strong collaboration with EPCC Contractors, maybe the answer to future projects looking for integrated smart solutions.
Floating Roof Storage Tanks Life Extension: A Novel Risk Revealed
Authors: Al Omari Ammar , Herzalla Osama , Toubar Ashraf , Almalood Naser , Al Hammadi Hassan
Published: November 2019

External floating roof crude oil storage tanks are widely used in the Oil & Gas industry due to many advantages. Floating roofs in storage tanks are well-known in minimizing product losses due to evaporation. The floating roof systems also mitigate fire risk by eliminating vapor space beneath the roof. However, the operation of such massive structures brings different challenges. This paper reveals the relation between floating roof mechanical deformation and tank floor settlement. This research studies a real case of a floating roof storage tank. The double deck floating roof experienced an excessive mechanical distortion in form of bulges and undulations at roof lower deck. A Finite Element (FE) Analysis studied the relation between tank bottom plate settlement and roof deformation while roof is in parking position. The roof bulges were dimensionally surveyed and compared with FE results. The FE Analysis results of stresses and strains were utilized to decide the integrity condition of the tank roof and to study the behavior of the existing bulges for continued operation of the tank roof.

During storage tank major overhaul, bulges were reported in the lower deck of the floating roof with 50-100 mm depth. The bulges are in form of waviness and they are more severe in the roof middle pontoons. The simulation results showed that while the roof is parked over a floor with non-uniform settlement, some of the roof supporting legs will be engaged with the tank floor earlier. This will lead to a non-uniform weight distribution of the tank roof over the legs, and overloading the roof lower deck with bending stresses. The FE results were able to define the location of the induced high stresses that may lead to cracking in the welding lines of the roof lower deck plates. It was decided to conduct a magnetic particle inspection at those critical lines to ensure they are crack-free. Results showed that the stress levels in the roof will reduce dramatically after refilling the tank and floating the deformed roof, this is due to the redistribution of the roof weight uniformly over the product surface. After refilling the tank, plates with elastic bulges will recover and plastically deformed bulges will have lower stress levels. The assessment concluded that storage tank floating roof is fit for service. The relation between storage tank floor settlements and floating roof deformations has never been analyzed to this depth of engineering analysis. The storage tanks international codes state that bulge sizes in the floating roof shall be kept as minimal without providing any acceptance criteria. This research quantifies the acceptance limits of floating roof bulges based on an advanced engineering simulation.
Application of Machine Learning Approach for Intelligent Prediction of Pipe Sticking
Authors: Abbas Ahmed K. , Almubarak Haidar , Abbas Hayder , Dawood Jawad
Published: November 2019

Stuck pipe has been recognized as one of the serious problems in drilling operations that has a significant impact on drilling efficiency and well costs. The events related to the stuck pipe can be responsible for losses of hundreds of millions of dollars each year in the drilling industry. This paper presents a study on the application of machine learning methodologies to predict the stuck pipe occurrence which can be utilized to modify drilling variables to minimize the likelihood of sticking. The new models were developed to predict the stuck pipe incidence for vertical and deviated wells using artificial neural networks (ANNs) and a support vector machine (SVM). The proposed models were examined using a few examples of real stick pipe cases from the field. The results of the analysis have revealed that both ANNs and SVM approaches can be of great use, with the SVM results being more promising.

The present analysis supplies knowledge that can be used during well pre-planning and developmental phases to make informed decisions that will avoid pipe sticking problems and essentially optimize drilling performance. The risk of pipe sticking can then be minimized and the costs associated with its occurrence will be reduced.
The First Deployment of a Fully Electrical Intelligent Completion System in 3-Dimensional Complex ERD Wells in the Caspian Sea
Authors: Kosset Talgat , Sissenov Olzhas , Novokshenov Stanislav , Niverchuk Andrey , Golenkin Mikhail , Zvyagin Vasily , Nabiullin Renat , Dadashev Afrand
Published: November 2019

Extended-reach drilling (ERD) from a fixed offshore platform poses unique challenges for anticollision directional drilling and wellbore construction. Wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and ERD wells are becoming common in the Russian sector of the Caspian Sea. An integrative approach and advancements in drilling and completion technologies in the Korchagina field have enabled enhanced hydrocarbon recovery through extreme reservoir contact from ERD wells.

Various issues, such as wellbore stability, borehole geometry, torque and drag, and borehole condition can affect the deployment of completion hardware to the desired depth. This paper presents the installation of ground-breaking technology in an ERD well in which the longest fully electrical intelligent completion was landed successfully through proper design and careful planning. The paper will also present the planning and execution of three ERD wells completed by use of a fully electrical intelligent completion consisting of multiple downhole active flow-control devices controlled by a single downhole electrical line. The installation of these completion systems allowed the operator to control the breakthrough of water or gas or both, to selectively produce additional hydrocarbons from multiple zones and compartments in real time, and to minimize the number of required production logging tool runs.

In 3D complex well profiles, while running the long completion string, axial drag is accumulated along the string, which exposes it to sinusoidal and helical buckling. Excessive compressional loads in the string beyond the buckling limit of the pipe can lead to lockup and ultimately prevent the string from reaching the setting depth.

This paper presents a structural integrated approach for successfully deploying a fully electrical multipoint pressure and temperature measurement completion systems on 3 ½-in. and tapered 3 ½ × 4 ½-in. tubing by using a wireless electric connect-disconnect system.
Middle East Gas Field Case Study Proves Step Change in BHA Reliability Through New HFTO-Isolation Tool
Authors: Heinisch Dennis , Kueck Armin , Herbig Christian , Zuberi Mamoon , Peters Volker , Reckmann Hanno
Published: November 2019

Self-excited torsional vibrations of the bottomhole assembly (BHA) at frequencies above 50 Hz, so-called "high-frequency torsional oscillations" (HFTO), can damage drilling tools and can increase non-productive time (NPT). A recently developed HFTO-isolation tool protects the drilling tools above this tool from these harmful vibrations. More than 200 field runs were investigated to evaluate the changes in reliability and benefits.

The concept of the isolation tool works similarly to a two-mass flywheel used in automotive drive trains. The design was simulated, lab-tested and first deployed in a field run in 2018. Since then, the isolation tool was successfully used in various fields and applications in the Middle East. HFTO severity while drilling was measured and recorded below and above the isolation tool to verify functionality and to quantify reduction in torsional loads (torque, tangential acceleration) for the measurement while drilling (MWD), mud pulse telemetry (MPT), and logging while drilling (LWD) tools above the tool. In addition, HFTO-related incidents and other drilling performance indicators with and without the new tool were analyzed.

Analysis of the recorded vibration data from several field runs with an additional high-frequency MWD-tool reveals that the isolation principle works consistently. As predicted by simulation, the measured torsional vibration amplitudes above the tool are significantly lower than without using it, demonstrating the effective protection for MWD-, LWD-, and MPT-tools in the BHA.

The tool has proven consistent performance in more than 16,000 accumulated circulating hours. Tool failures caused by HFTO were eliminated, compared to 22 percent of all failures without the isolation tool. The results of an analysis of individual MWD- and MPT-tools used in runs with and without the isolation tool show a significant increase in distance drilled per tool deployment and re-run decisions. This directly translates to increased asset utilization, fewer trips for failure, and BHA handling operations that results in less non-productive time (NPT) and enables drilling in extremely challenging environments more efficiently.
Application of Machine-Learning to Construct Simulation Models from High-Resolution Fractured Formation
Authors: Santoso Ryan , He Xupeng , Hoteit Hussein
Published: November 2019

In modeling fractured reservoirs, outcrops may offer useful insights about the subsurface characterization of the heterogeneous rock formation. They provide analogs that could be replicated in the reservoir to capture the fracture and matrix characteristics, which are crucial to assess the governing recovery mechanisms. Constructing outcrop-based reservoir models is a labor-intensive process, which is subject to personal interpretation and error. In this work, we propose a novel workflow for modeling fractured reservoirs within a deep learning framework. The workflow consists of three main steps that include fracture network recognition to map explicitly the fractures from digital images, fracture characterization to provide an assessment of the fracture effective hydraulic apertures, and reservoir model construction to integrate the multi-scale data and construct the up-scaled simulation model. In this paper, we focus on the first step in the workflow.

The fracture network recognition starts with segmentation for the images of the fractured formation. The ultimate objective is to identify the fractures from RGB, greyscale, or hyperspectral images. We developed a U-Net-based algorithm to perform the segmentation using 64×64 pixel-resolution. This resolution is carefully selected to accelerate the fracture recognition process and to narrow down the variability in the training set. The inputs are images of the fractured medium with any resolution which are pre-processed before feeding it to the recognition process. The output is a list of the identified fractures, where each fracture is composed of a set of segments, and each segment is defined by the coordinates of its end-points. The output format could be readily processed by any fracture modeling software.

We demonstrate our workflow to recognize and identify fractures from different 2D images, where we discuss the machine-learning (ML) training and testing stages. The algorithm shows accurate predictions and identifications for the fractures. This workflow has the potential to be extended and applied at the field scale.
A Case Study of High H2S Aquifer Production Testing : Planning and Execution
Authors: Aman Shah Muhammad Kamal , Mudaliar Kokulananda , Mamat Mohammad Shahrin , Salleh Zaimi
Published: November 2019

This paper shares a case study of production testing of a large Middle East dolomitic aquifer containing high concentration of H2S. The aim of this paper is to discuss on the HSE aspects primarily on wellsite and operation safety by sharing the issues, challenges and mitigations at various stages of planning and execution.

As part of field X development strategy, water flooding is required to maximize recovery. However, due to water scarcity Operators had to look into ground aquifers to support water injection leading to dolomitic reservoir being identified as the best source. The initial planning was based at 30 ppm H2S limit centered on samples obtained from nearby field located 400 km from field X. Based on actual bottomhole samples from field X, it was found that the reservoir contained higher H2S concentration which requires the operator to re-strategize the production testing operation within a limited time frame to cover safety and security aspects.

The operation involved multidisciplinary collaboration encompassing DST design, process safety and security. As the well is located in a densely populated area, a first of its kind H2S dispersion study in aqueous solution was introduced.

The DST operation was successfully conducted with no major HSE and security incident recorded. The well was tested up to a maximum rate of 20 kbl/d and through the introduction of multiple injection point, the concentration H2S was successfully reduced to 2 ppm.

The H2S dispersion study in aqueous phase played a pivotal role, assisting in risk identification and quantification. Through the study, many critical HSE aspects were addressed and resolved, expediting the planning stage and improved the whole system. The modelling was based on worst case scenario where all 18,000 ppm of H2S will disperse to air. On the other hand, for normal operation, some portion of H2S is expected to dissolve in water during discharge. It is also noteworthy to mention that understanding the limitation of the model is equally important to assist in planning and executing the operation effectively.
Integrity Challenges Associated with Cathodic Protection Application & Resolutions
Authors: Al Salmi Ebrahim Salem , Al Ameri Saleh Salem , Al Ameri Ayedh Saeed , Girkar Shakeel Isak , Nair Ajiv Mohan
Published: November 2019

ADNOC Onshore is one of the leading Middle East Oil Operator has more than 60 Pipelines and 3000 Well casings. All buried structures are externally protected against soil-side corrosion with Coating and CP.

Corrosion and subsequent failure, particularly on pipelines/well casings is one of the main factors upsetting any upstream/downstream production facilities. Maintaining adequate level of CP system is always a challenge for corrosion engineers due to complex corrosion phenomena. Failure of these pipelines/well casings during production stage due to corrosion can be catastrophic with following consequences:·Loss of life (fatality)·Safety and Environment (Fire, Toxic gases and Oil Spill)·Resource and downtime cost impact·Damage to asset/company reputation.

As per current industrial practice, the buried structures is designed to be protected externally by coating wherever possible along with ICCP system. However, the CP effectiveness often becomes challenging due to the CP interference caused by Ground beds and other structures since adequate separating distance cannot be maintained practically due to the field congestion.

This paper focuses on case study of a Ground bed in the vicinity of a buried pipeline, CP interference during CP effectiveness evaluation, Interference tests, crowding effect due to two or more deep anode bed systems operating in single rectifier, possible corrosion and damage mechanism and also strategy for remedial measures like ‘Shielding’ to nullify the Interference effect along with recommendations.
Use of Artificial Intelligence to Measure Gas Flow Rate, Bongkot Asset
Authors: Ketmalee Thanapong , Sirisawadwattana Jutaratt , Piyajunya Tanunya , Ngamkamollert Krit , Bandyopadhyay Parthasarathi , Whangkitjamorn Jugkapun
Published: November 2019

Greater Bongkot North is a gas field located in Gulf of Thailand and on production since 1993. Most of the old wellhead platforms (30%) lack remote well test facilities which requires personnel visits for any well test measurement. Often, well testing in these platforms get lower priority compared to other operations in a matured field. This project implemented artificial intelligent (AI) technique to estimate gas rate from other available engineering and geological parameters.

A new approach using machine learning was applied to estimate gas production rate where actual measurements are not available. Actual production well test data was used to train the model. Input parameters used were:

Surface facility information Fluid properties Production condition Geological setup

A blind test on the subset of historical data showed a level of confidence (R2) value of 0.93. This provided confidence to proceed with a full field pilot. A pilot was conducted during January to May 2018. The area of pilot was spread across various geological, operating and surface condition setups to reduce sampling bias. The pilot demonstrated the following use cases:

Improved prediction accuracy in wells with no recent test, achieving primary object of model. Detection of well behavior changes: The model could detect changes in well behavior without human intervention much before the trends become obvious for engineers to detect. Improved potential estimation in wells with leaks in wellhead chokes where conventional analysis followed in Bongkot is not possible due to improper wellhead shut-in pressure measurement. Improved efficiency with production allocation: The conventional method requires significant time (40-80 person hours per month) to make the data available for production allocation. This can be shortened significantly by use of this method

In essence, this project demonstrated the potential use of artificial intelligent to improve efficiency in a matured gas field operating under marginal conditions.