bluuebunny/crossref_metadata_2025 huggingface dataset:
Paleo Environment Analysis Using Geochemical Data of the Intershelf Basin in Cenomanian, Cretaceous of Abu Dhabi
Authors: Yamanaka Motoyoshi , Amo Miki , Nanjo Takashi
Published: November 2020

The central part of the Cenomanian intrashelf basin in Abu Dhabi is composed of mudstones with high TOC concentration. The mudstone with high TOC in the Cenomanian interval is divided into three zones as named of OAE1d, MCE, and OAE2 of OAE (Ocean Anoxic Events). In this study, the two wells (Well A and Well B) were re-evaluated to confirm carbon isotope curve (chemostratigraphy) and geochemical/biomarker analysis including TOC measurement and to consider paleo environment developing these mudstones within the intrashelf basin.

Regarding this intershelf basin, there are several papers to study of the relationship between TOC (Total Organic carbon) and OAE (Ocean Anoxic event) using geochemical analysis. We conducted core observations, GR log correlation, carbon and oxygen isotope analysis, trace elements analysis, mineral mapping, TOC analysis and biomarker analysis of two wells. Sampling was taken at 3ft for both wells. The results of carbon isotope were almost the same as the OAE zone (three OAE zone from lower to upper OAE1d, MCE and OAE2) within previous studies.

Flat ammonite/inoceramus in OAE1d mudstone were recognized in both wells. It is highlighted that the ammonite/inoceramus indicates a good example to understand the productivity and preservation of the OAE. The cross lamination of mudstone contained ammonite/inoceramus had not received any bioturbation, therefore, the OAE1d interval is considered to have been buried earlier than biodegradation. This mudstone shows the alternation of gray- and dark-colored (each thickness is 10-30cm) and high TOC contents around 11-13%. However, mineral mapping suggested that illite and pyrite were only partially confirmed in well B. Same samples were increasing C35 Homohopane. Regarding paleo topography, well B was located near hinterland area, which provided carbonate debris with clay minerals. In addition, the results of two wells are plotted with variation of C28 sterane in the ternary diagram. However, oil samples in the Afield located on east side of intershelf basin are plotted in the almost same area in the ternary diagram. The differential was dependent on seawater circulation between intrashelf basin and open marine of Eastern Tethys. By combining the newest technologies like carbon Isotope, ICP-MS, mineral mapping analysis and biomarker analysis, this allows an in-depth understanding of regional geological interpretation. In addition, core and thin section observation is an essential part to the geological understanding.
Virtualization in Operational Technology OT Environment
Authors: Mookonil Vijay , Almeqbaali Meirah
Published: November 2020

The objective of this paper is to present the Virtualization concept, its anticipated benefits and demonstrate how it is the future for OT (Operational Technology) environment and Oil & Gas industry in general.

In ADNOC Gas Processing plants, there are several control systems commisioned and operational. Majority of these systems such as Distributed Control system (DCS), Supervisory Control And Data Acquisition System (SCADA), Emergency Shutdown System, Fire & Gas Systems, Turbine Control System, Anti-Surge Control Systems, etc. are very critical operationally, due the safety of the plant. Lifetime of these assets is not as long as it used to be in our industry during the past few decades, due to various dependencies and concerns related to Operating Systems obsolescence and the associated dependency on the hardware.

All Control System applications run on various versions of Microsoft Operating System (OS), as Microsoft is the sole Windows operating system supplier, to supports computer's basic functions & interact with advanced applications and control peripherals.
Production Flow Comparison Between Distributed Fiber-Optic Sensing and Conventional PLT in a Cased Hole Horizontal Wellbore With ICD
Authors: Hveding Frode , Guraini Walid , Mahue Veronique , Hafezi Sina
Published: November 2020

A cased hole well with inflow control devices (ICDs) was logged for production profiling as part of a field trial campaign testing a new fiber-optic wireline system. Pulled by a conventional tractor, both the fiber-optic wireline and a set of conventional production logging tools (PLTs) were placed at the bottom of a horizontal wellbore, locating the fiber across the reservoir for sensing purposes. The well produced at two different choke settings, enabling both technologies to capture low flow rate as well as high flow rate. The main objective with the testing was to compare the two technologies for production flow allocation and learn more about fiber-optic analytics.

The two different measurements were performed as close in time as possible. While the fiber-optic cable was sensing, the PLT was stationary and not logging, and while PLT was logging, the fiber optic was deactivated. From fiber optics, high-quality noise logging plots were generated with distributed acoustics (DAS), identifying the inflow points despite the relatively challenging acoustic environment. Propagating sound allowed for a profile of fluid sound speed to be established. Distributed temperature (DTS) was less useful on this job due to some accidental inflow of borehole fluid causing hydrogen darkening. This affected the multi-mode fiber more than the single-mode fiber; hence, DTS data could not be used. The wireline-based MAPS tool consisted of capacitance-, resistivity- and spinner-array. With the sensors located on bow springs, the tool detected various flow patterns 360 degrees around the borehole. The fiber-optic cable is located low side in a horizontal wellbore and might be affected by this in a laminated flow situation. Still, the fiber-optic sensing system managed to provide useful flow information, comparable to the PLT tool.
Prediction of Lost Circulation Zones Using Artificial Neural Network and Functional Network
Authors: Ahmed Abdulmalek , Elkatatny Salaheldin , Ali Abdelwahab , Abdulraheem Abdulazeez
Published: November 2020

Drilling high-pressure high-temperature (HPHT) wells lead to many difficulties and issues. One of the most difficulties during the drilling is the loss of circulation. 40% of the drilling's cost is belong to the drilling fluid, so the loss of these fluid causes an increasing in the total drilling operation's cost. Circulation loss has many consequences related to well control which can lead to the worst case of blowout. There are several approaches to avoid loss of return, one of these approaches is preventing the occurrence of the losses by identifying the lost circulations zones. However, most of these approaches are difficult to be applied due to some constraints in the field.

The purpose of this work is to apply two artificial intelligence (AI) techniques to identify the zones of lost circulation. A data of real-time surface drilling parameters from three wells were obtained using real-time drilling sensors. The two methods of AI are functional networks (FN) and artificial neural networks (ANN). Well (A) was utilized to build the two AI models by dividing their data into training and testing. Then, well (B) was utilized to validate the developed AI models.

A high accuracy was achieved by the two AI models based on the root mean squared error (RMSE), confusion matrix and correlation coefficient (R). Both AI models identified the zones of lost circulation in Well A with high accuracy where the R is more than 0.98 and RMSE is less than 0.09. ANN is the most accurate model with R = 0.99 and RMSE = 0.05. Moreover, ANN was able to predict the lost circulation zones in the unseen well B (R = 0.952 and RMSE = 0.155).
World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas
Authors: Hamdan Tariq , Turpin Craig , Husein Mohamad , Alblooshi Salem , Alhammami Mohamed , Hussain Mohamed , El Shahat Ayman , El-Meguid Mohamed , Oko Vincent , Al Ramahi Basil , Abbas Fady
Published: November 2020

The objective of this paper is to demonstrate the challenges, solutions and results of performing offshore Drilling Waste Management operations in a highly environmentally sensitive marine environment and UNESCO World Biosphere Reserve in offshore Abu Dhabi.

The solution was to treat all drilling waste at source. This required both NOV Thermal Treatment Technology and NOV Cuttings Re-Injection Technology and became the World's first single-source operation for this equipment. The equipment was shipped to the island, installed and operated in parallel with the Operator's drilling programme. The drilling waste (Oil-Based Mud) was handled and stored by EMDAD then processed through the NOV Thermal treatment unit, which generated three separate treated waste streams - oil, water and solids. The recovered oil and water were reused on-site, whilst the treated solids were slurrified and fed to the NOV Cuttings Re-Injection system (CRI), which injected the solids into a disposal well.

This paper will also demonstrate the results of the integrated operation.
Tamuh: Implementing A Graduate Development Scheme for Fast Tracking Young Professionals in Petroleum Development Oman
Authors: Lamki Amal , Abri Yaqoob , Al-Jumah Ali , Mahruqi Shabib
Published: November 2020

Strengthening Technical and business skills with new perspectives, thinking and new insights are critical to ensure high performance and value creation in the short- and long-term. Nimr Cluster relentlessly aspire be renowned and respected for the excellence of our people and the value we create for Oman and all our stakeholders. In the midst of disruptive time where 'Do More with Less' is a guideline we have innovated and persevered the journey of professional / personal development - Make the Future - Oman 2040!

Nimr Cluster in Petroleum Development Oman's (PDO) south oil directorate is one of the first clusters to implement and enroll graduates in the Graduate Development Program (GDP). This is a tracking tool to ensure a balance between staff development as well as delivering business activities.

This approach provides a focused Staff Development to Progression, with Clear synergy with Function and Business needs to drive individual aspiration to progress.

The cluster in question, Nimr, is the biggest in the Oil South Directorate, comprises more than 20 fields with different production mechanisms, including depletion, polymer and Waterflood. It also has more than 2,000 active wells, the highest count for an individual asset in PDO, and delivers a substantial amount of produced oil. The scope and scale of its operations gave the Nimr leadership a significant opportunity to make efficiency improvements.

Nimr Cluster started to implement Tamuh since 2019, and that took three stages. It started by hard copy tracking sheet in 2019 into a fully digital tracking sheet in a cloud-based database that can be accessed by all. The coach and coachee balance is set and the Gemba is taking place in different level. Team leads and the cluster leader the function, and the petroleum manager level. This allows for better management from the graduate side, as the past situation had many factors to juggle and manage effectively.
Operations Excellence Journey on Digital in Enhancing Production Operations, Planning and Process Cycle Efficiency
Authors: Choudhuri Amit
Published: November 2020

Increased focus by Upstream Oil and Gas Companies to adapt to the current business environment has led to leveraging upon process simplification, Industry- 4.0 and digitalization programs for enhancing the field operations, reduce deferments and standardize planning processes inline to operational excellence. Objective is to lean current processes through developing lesser decision stage gates and providing input data bank for faster decision making, thus transforming the way of working into "value based" and improving on efficiency. In current business environment, digital solutions are being favorably viewed as enablers instead of disruptors, as was considered in the past. Digital solutions encompass development of model based technical workflows, lean business process workflows, robust planning methodology and integrated performance dashboards to enable informed and optimal decision making. Through this paper, experience from various Oil and Gas Upstream Operators in their journey of digitalization and in business and technical process simplifications will be shared, based on author's work and interaction with different oil and gas operators.
Automated Well Correlation using Machine Learning and Facial Recognition Techniques
Authors: Bakdi Sara , Kannan Nitish , Reddy Masini Shashipal , Chennakrishnan Balaji
Published: November 2020

This paper outlines the study results of machine learning application to automate well correlation. Algorithms are designed to address challenges such as geological field complexity, number of wells and geological horizons, and quality of log data, that are usually associated with well correlation

The Kansas state oil and gas fields, USA has more than 350000 wells and produced over 5 billion barrels of oil, with an estimated 11 billion barrels of oil still remaining underground. Nearly 100 wells from Thomas, Scott, Logan, Barton, Stafford and Wichita Counties are selected for this study.

Petrophysical data such as Gama Ray, Neutron, and Density logs, considered most sensitive for lithology and Geological Cores descriptions are used as input. Sedimentary facies variation from limestone, shale, sandstone and coal were used as indicators to separate stratigraphic sequences.

The approach followed is a 1D adaptation of panoramic stitching using feature vectors generated from a 1D Convolution Autoencoder. Convolutional autoencoders learn a compressed representation of input by first compressing the input using encoder and decompressing it back using decoder to match the original output This autoencoder is a neural network trained to reproduce input image in output layer, similar to facial recognition techniques. It identifies a series of matching points between a pair of well logs and trained to pick and match geological well tops.

In order to demonstrate the performance of algorithms in term of accuracy, speed and to address the range of uncertainties, more than 30 wells were used for training. The study results have demonstrated high level of constancy in automatically subdividing the reservoir units of different wells consistent with stratigraphy and consistent across wells even though distance separating for each individual well is considerably more than one kilometer.
The Success of Drilling Long Departure Wells with Light/Slim Casing Design in United Arab Emirates Onshore Field
Authors: Morales Annie , Salem Gamal , Asef Mohammed , Yamani Sultan Al , Nava Jose
Published: November 2020

This case study presents the challenges faced and learning curve built while achieving longer departures with light / slim casing design instead of conventional / heavier design in shallow coastal water field in UAE.

This paper intends to explain the challenges that were encountered and the process of mapping the lessons learnt to ensure improvements along the process.

The process involved the casing points analysis evaluating the competent formations options, continues optimization of well trajectory by increasing the inclination across problematic formations while drilling the intermediate section (limited in previous drilling campaign in the area), the evaluation of the impact caused in the consecutive 8 ½" phase (longer section), implementation of best practices to mitigate stability issues and Invisible Lost Time (ILT) methodology application to minimize hole exposure duration.

The challenging campaign had the objective of saving cost by reducing one [FQ1] construction [FQ2] phase and continues achieving longer departures successfully which was a milestone during the well construction, thus a learning curve was built focused on continuous improvement of key operations.

After completing more than 100 wells, the most beneficial point this change has offered is drilling long departure wells saving one phase in comparison with the conventional design in the area, which is the key element for cost reduction and also allowed to reduce crew exposure to heavier casing handling improving HSE risks.

Currently, a maximum departure/vertical section of 10,700 feet has been achieved with light/slim casing design. Overall duration saving is 16 days compared with the best heavy casing design duration and 20 days with average heavy casing design duration with 35% saving duration.

Drilling light casing design instead of conventional heavy casing design enable average of USD 2 million saving per well. The consolidated experience built throughout planning and execution since the first well, enabled an important performance improvement based on the learning curve built along the years.

Nowadays, many fields require drilling wells with long vertical section / departures to reach further targets, away from the feasible surface locations. Additionally, cost reduction is another concern due to Oil Market fluctuation by applying new strategies and optimizing the performance without jeopardizing but improving the HSE at the same time.

This paper presents a novel approach to well construction by showing the lesson learn that allowed well duration reduction, drilling more wells per year and consequently bringing early production, increasing efficiency and significantly reducing cost, therefore increasing productivity and profitability, at the time of contributing to HSE improvement.
Acid Prohibitive Flexible Cement Enables Long Term Zonal Isolation in High Temperature High Pressure Well
Authors: Anwar Rameez , Elmoneim Hossam A.
Published: November 2020

Cementing of production casing in the Northern Iraq poses challenges to the cement sheath integrity due to mechanical and thermal stresses induced in the well life. The problem is further aggravated due to narrow window between pore pressure and fracture gradient. The acid-prohibitive cement system with improved mechanical properties was developed to mitigate the effect of induced stresses. The job was executed with operational optimization and zonal isolation was achieved.

Based on the operator's well testing and multi-stage high-rate well stimulation plan, the stress modeling was carried out to determine the optimum mechanical properties. The 19.6 ppg heavyweight cement system with a flexible thermoplastic polymer was designed to achieve the required Young's modulus and Poisson's ratio. Since the density and friction pressure hierarchy could not be met due to the narrow window between pore pressure and fracture gradient, therefore, the slurry rheological properties were optimized for effective mud removal. The pumping parameters were adjusted to maintain the primary well control during the cementing operation without compromising displacement efficiency.

The approach was implemented without any operational issues in the 9-7/8" production casing and 7" liner cementing. Following the job completion and waiting-on-cement time, the 9-7/8" casing was successfully pressure tested with a surface applied pressure of 2,000 psi and a well fluid of 1.78 SG. The isolation scanner cement evaluation confirmed the zonal isolation along the open hole of both the 9-7/8" intermediate casing and the 4½" production liner. Finally, the multi-stage high-pressure stimulation operations were performed during the completion/testing stage with no sign of communication between the different zones. The application of heavyweight acid prohibitive flexible slurry helped the operator to isolate the different zones of interest that were less than 10 m apart and retained the integrity of the seal throughout the high-pressure stimulation operation. Well is open to production without any annular pressure, thus, saving the operator's time and cost on the remedial cementing operations.

The proposed solution will help operators to ensure long-term zonal isolation in the HTHP wells which are subjected to dynamic pressure and temperature changes in the post slurry placement phase. The operators can also avoid the time and money on expensive remedial operations.
Controlling Congestion and Connectivity in Field with Multiple Reservoirs
Authors: Alhemeiri Sultan , Al Shehhi Mohamed , Soares Sofia Da , Chellappan Sanjeev Kumar , Wei Wei , Al Maysari Jawhara , Idicula Anoop Pappy
Published: November 2020

ADNOC Onshore operates a sour field on South West of Abu Dhabi with the wells to the northeast of the field exhibiting generally higher H2S content than wells to the southwest.

Congestion of the field is recognized as a major issue affecting safety, access to existing reserves and operability since the early 2000. The congestion is caused by the high density of surface facilities resultant of numerous interfaces in the field (stakeholders), making well surface location finalization very challenging and impacting directly on subsurface congestion (by risking or impairing access to lower staked reservoirs - subsurface collision), rig moves, field connectivity, etc. This poses serious challenges to future developments if the approach of business as usual were to continue.

The field has been producing from several oil and gas reservoirs but accelerated plans for oil and gas long term developments extended the exploration to other new reservoirs, increasing the challenges on reservoir exploration (brown field vs green field approach), on safety (exponential increase in number of wells, reservoirs with higher H2S content, etc.). It also increases surface and subsurface congestion, as the complexity of producing from more staked reservoirs increases.

Decongesting the field and controlling the associated congestion of on-going projects is a key activity to manage space for future development, sustainable operation and business continuity. So far, the evaluation of a certain project options in terms of footprint impact has been qualitative in the sense that the decision is made based on the congestion observed on Enterprise Geograhic information System (GIS) map and in order to quantify footprint use and achieve a trustworthy comparision mechanism, a Geograhic Iinformation System (GIS) based congestion factor calculation tool had to be developed.

This paper covers the development of the Congestion & Connectivity tool as an important milestone in ADNOC Onshore's initiatives to quantify and address the congestion issues on surface and consequently on subsurface and extend to other ADNOC Onshore in the long run.
A Major Shift In Reservoir Management Strategies And Best Practices In A Mature Reservoir To Overcome The Current Reservoir Challenges: Case Study
Authors: Alshalabi Alaa , Al Saadi Haitham , Maire Flavien , Thomas Tony , Gueye Talla , Al Amiri Fatema
Published: November 2020

Reservoir X is a giant oil reservoir of 30×10 Km2 developed since 1973 using peripheral water injection. A major review study was done in 2016 highlighted major reservoir challenges that need to be managed and mitigated. The main challenges are (a) reservoir pressure decline in the central area (b) advancement of water cut/water conning (c) increased number of inactive strings (d) improper distribution of production offtake (e) inefficiency of current injection scheme. Consequently, reservoir deliverable potential has continuously dropped with increasing inactive strings threatening the attainment of the field mandated production target. This requires a major shift in our reservoir management strategies and best practices to cope with these challenges.

In this paper, a case study for reservoir management in a mature carbonate reservoir with its detailed methodology is presented. An intensive and integrated technical work was conducted to (a) regain the target technical rate of 20% (300Mbpd) (b) arrest the pressure decline (c) implementation of a more efficient long-term plan to increase reservoir pressure and to maximize ultimate recovery. A detailed approach was developed which consisted of short, mid and longterm actions. This approach involves (a) re-prioritization of infill drilling through weighted ranking (b) pressure recovery implementation strategy through sectorization, re-balancing of production offtake and improving water injection efficiency (c) sector based evaluation using simulation/streamlines/data analysis for the voidage replacement (e) water injection optimization with the help of new peripheral water injectors, increased water injection availability (New clusters and network debottlenecking) and new Water Injection scheme (Mid Flank water injectors) (f) tracking the implementation of the Pressure Recovery Plan with a dedicated and tailored monitoring dashboard.

Through this integrated approach a portfolio of wells is selected and ranked that help in achieving the objectives of the reservoir development efficiently and the 20% Technical Rate achievement. The sector wise analysis and tracking approach enabled in arresting the pressure decline in the crestal area and ensured that the focus remained on the recovering pressure in the worst affected areas of the reservoir while meeting the production requirements. Another important outcome of this work was to drive a slew of initiatives related to the improvement of water injection efficiency that is a necessary requirement to recover the pressure in the crestal area. This reservoir management methodology and framework put in place provides a platform to continuously integrate the inputs (production/injection; VRR; pressure) and develop understanding from the different disciplines of the reservoir development to monitor and manage the reservoir in and efficient and timely manner.
Well Depth Monitor Software Design Based On Laser Distance Measuring Device
Authors: Han Haochen , Hu Yongjian , Zhang Yong , Sun Qi , Sun Chengqin , Fang Zhimeng , Chen Haoweu
Published: November 2020

Well depth is one of the most valuable parameters in drilling engineering. Commonly well depth is calculated by the absolute difference in height based on the revolution of drawwork sensor, which is a pulse encoder or incremental optical encoder. Both encoders have complicated calibration process, and the measurement is easily disturbed.

Different from the traditional indirect measurement from the drawwork sensor, the direct measurement provided by laser distance device can simplify the process and decrease the systemic error. The principle of the measurement is to calculate the distance by the product of the atmospheric refraction coefficient and the speed of light. In our design, we fixed the laser distance device on the hook and placed the reflector under the crown to measure the height variant. Modern industrial laser distance device with high accuracy can finish multiple measurements per unit time and calculate the average to reduce the measurement error effectively.

The well depth measurement system software based on laser distance measuring device can shorten and simplify the calibration process or even realize automatic calibration. The laser distance measuring device can be used effectively in the severe weather, such as strong winds, and minimize the error caused by manual operation. We completed the optimization of laser distance sensor and selected Sick DL 100 as the main laser sensor, as well as a laser measurement prototype in lab. After thousands of trials and errors, it turns out to be applicable. In order to be compatible with the new well depth measurement system, we developed a corresponding software by .Net Framework and WPF. With the help of .Net framework and WPF, UI and core codes of the software are separated in physical isolation, which can improve the development efficiency and make preparation for further extension and optimization. The software supports portal communication and ethernet, which can connect with the laser distance device conveniently.

By the well depth measurement system software based on laser distance measuring device, we simplified the well depth measurement calibration, reduced the system error and improved the accuracy of measurement. The application of this system contributes to the drilling operation and shortens the drilling period.
Research on Tubing and Casing Anti-Bending Technology for Salt Cavern Gas Storage Cavity Construction
Authors: Cen Xueqi , Zeng Hao , Wang Haibo , Huang Xiao , Zhang Rusheng , Wang Lei , Gao Shengen , Liu Fang , Huang Qingfeng , Wu Junwen , Zhang Le
Published: November 2020

Benefiting from its outstanding gas injection-production capability and fully recoverable cushion gas, salt cavern gas storage technology was developed rapidly in recent years. Wangchang salt cave gas storage is characterized by deep burial depth and multiple interlayers. The project of water-soluble cavity construction faces problem of serious tubing and casing bending and deformation. Therefore, development of effective tubing and casing string damage-prevention and risk control method remains an ongoing challenge.

Both theoretical study and field tests are presented in this article. Through field observation, mechanical analysis and production data analysis, it was identified that the main reasons causing tubing and casing bending are liquid-solid coupling instability, interlayer rock impact and smashing, as well as pipe string wear and corrosion. By optimizing the tubing and casing strings design and adjusting production parameters, tubing and casing bending problem could be effectively improved. Besides, remedial measures to deal with bending pipe string were proposed.

Critical destabilizing flow rate of the tubing and casing was calculated under different diameter and wall thickness conditions. Analysis of calculation results showed that the current water injection volume of the Wangchang gas storage well was higher than the critical displacement. It was verified that the liquid-solid coupling instability was the main reason causing tubing and casing bending in the gas storage well. Field data analysis showed that large water injection displacement and high water injection pressure fluctuation was more likely to cause bending and damage of tubing and casing. Technical measures are listed as following: (1) strengthening the steel grade wall thickness of intermediate casing; (2) equipping the central tubing column with a drop connector to optimize the distance between the central tubing shoe and the middle casing shoe; (3) Optimizing the cavity water circulation method to stabilize the water injection pressure and displacement.

The anti-bending technology presented in this study unlocks a critical bottleneck during the salt cave building progress, which is the tubing and casing bending and deformation problem. With the application of this method, efficiency of water-soluble cavity building can be greatly improved. More importantly, this technology might pave a new way for the deep multi-interlayer salt cavern gas storage design.
Virtual Reality Simulators in the Oil & Gas Industry Review of Existing Solutions and Method for Evaluation
Authors: Qrain Afra Al , Reddy Ganga , Jadhav Satyaprasad
Published: November 2020

Plant operators and maintenance personnel form majority of the workforce in ADNOC Gas Processing. Ensuring their safety and competency is crucial. Over the past few years, ADNOC Gas Processing (company) has observed that a great deal of resources are spent annually on conventional training methods that are inefficient in terms of time, cost, and knowledge retention. With the advent of many technologies, Virtual Reality is found to be gaining ground; however, there are no clear guidelines on how to properly assess and select a one-stop VR solution that is sustainable and fit for the future.

This paper presents a review of VR solutions in the oil and gas industry through the development of multiple prototypes (proof of concepts) in collaboration with many solution providers. The objective was to: 1) Establish a learning experience and knowledge about VR main features, hardware, software and applications, 2) Evaluate the capabilities of various VR solutions in the context of field operator and maintenance training, 3) and develop guidelines or minimum functional design requirements for implementing VR.

Although all VR solutions shared similarities, there were some key differentiators that are considered success factor when selecting a one-stop VR solution. Examples of such factors include the ability to seamlessly convert CAD format to VR environment with high graphic and visual effects. VR should also allow the interactivity of 3D objects to its finest details, and render spatial sounds. Moreover, it should have inbuilt or integrated learning management system to record competency assessments of the trainees, and so many more as explained throughout this paper.

VR Field simulator is used in many applications and accrues several benefits such as reducing raining cost, improving people's competency, increasing efficiency as projects investment is recovered quickly, improving HSE as all types trainings can be delivered off-site, enhancing performance since it allows accurate off-site planning, and validates ergonomic design before commissioning
Leverage Energy Optimization to Reduce Carbon Capture Cost
Authors: Sajjad Saqib
Published: November 2020

The cost of carbon capture is the major impediment in its mainstream acceptance, but its ability to abate the carbon emissions at a considerable scale, makes it a technology with promising potential. The paper presents detailed account of the energy optimization meticulous review carried out for a brownfield project to capture carbon from the Sulphur Recovery Unit (SRU) Tail Gas. The paper demonstrates the vital role of energy optimization in restraining the carbon capture cost.

The methodology comprised development of an overall integrated heat & power model of the process encompassing energy supply sources, including power generation and import, and major energy consumers like CO2 absorption solvent regenerator, CO2 compressor and dense phase CO2 pump etc. The optimization was achieved by setting the objective function to minimize energy cost in terms of steam & power demand, by relating the selection of major drivers i.e. electric motor or steam turbine, as well as solvent, with the total energy cost in conjunction with the associated CAPEX. It followed with a meticulous review of individual systems and components.

Comprehensive energy optimization exercise, equating energy supply, major drivers’ selection and process decisions with the total energy cost and the associated CAPEX minimization, facilitated in carbon capture cost reduction by more than 10%. The optimized scheme helped in maximizing the utilization of available waste heat as well as in minimizing the spare steam dumping in condensers. The exercise confirmed the absolute significance of the energy optimization measures in reducing the cost of carbon capture.
Determining Initial Hydrocarbon Saturation Under Petrophysical Uncertainty Applying Machine Learning
Authors: Neff Pascale , Steineder Dominik , Stummer Barbara , Clemens Torsten
Published: November 2020

The initial hydrocarbon saturation has a major impact on field development planning and resource estimation. However, it is derived from indirect measurements from spatially distributed wells applying saturation height modelling based on uncertain parameters. The methodology presented here is deriving posterior parameter distributions by using Machine Learning in a Bayesian Framework honouring the petrophysical uncertainty in the field. The results are used for initialization and will be applied for forecasting under uncertainty.

To determine the initial hydrocarbon saturation, the Saturation Height Model (SHM) needs to be conditioned to the interpreted logs. 2500 geological realizations were generated to cover the interpreted ranges of porosity, permeability and saturations for 15 wells. For the SHM, twelve parameters and their ranges were introduced. Latin Hypercube Sampling was utilized to generate a training set for Machine Learning models (ML). The trained ML models were conditioned to the log derived saturation data. To ensure a field wide consistency of the models only parameter combinations honouring the interpreted saturation range for all wells were selected.

The presented method allows for consistent initialization and for rejection of parameters that do not fit to observed data. In our case study, the most significant observation concerns the posterior parameter distribution of the Free Water Level range which is narrowed down. Furthermore, the SHM parameters are proven independent; thus the resulting posterior parameter ranges for the SHM can be used for conditioning production data to models and subsequent hydrocarbon production forecasting. Additional observations can be made from the ML results such as the correlation between wells, this allows interpreting groups of wells that have a similar behaviour, favour the same combinations and potentially belong to the same compartment.

A workflow is introduced honouring the interpreted error of log derived porosity-permeability and saturation data. The workflow is based on Saturation Height Modelling (SHM) to generate a training set for Machine Learning. The SHM is conditioned to all wells in a Bayesian Framework to ensure that the posterior parameter distributions of the SHM are consistent and can be used for conditioning dynamic models to dynamic data and production forecasting.
Efficient Utilization of N2 During Commissioning and Startup
Authors: Al Jarwan Abdulla , Bin Kuwair Majid , Mokhbat El-Hachemi , Al Ali Hassan , Al Khanbooli Mohamed , Al Shamsi Mohammad , Kobbia Ibrahim , Al Wahedi Faisal
Published: November 2020

Efficient Utilization of N2 during Commissioning and Startup

In one of ADNOC's mega projects, Nitrogen was utilized for commissioning as well as start-up purposes, saving time and assessing equipment performance much earlier than planned. This paper which will be sectionalized in two parts, presents an extraordinary approach out of the norms for the usual nitrogen use in upstream oil and gas industries of purging and blanketing, resulting in significant savings in time and expenditure.

Commissioning with N2

There are many arguments about the risk / reward relation when it comes to applying Field test run with an inert gas (N2) ahead of hydrocarbon in, involving high pressure centrifugal compression systems. This part aims to discuss the advantages of adopting N2 testing well ahead of gas-in, challenges and rewards. Although the codes from API and ASME give details on the requirements of running compressors with gases different of design ones. The installation, the procedure, and the acceptance criteria are subject of agreement between vendor and company. Therefore, it's important to detail and agree with the Vendors on all process and mechanical criteria, limitations and necessary precautions ahead of adopting such tests. Additionally In this part, the various requirements to adopt testing high pressure compressor with N2 gas will be presented and along with a discussion on their capabilities to detect a variety of problems. Some issues which occurred during the N2 test run at site will be described.

Based on test characteristics and at the related cases, recommendations are made when ordering new compression system with considerations regarding the return of investment of these tests.

Startup with N2

Nitrogen (N2) was used as a stripping medium during the initial startup of the plant facilities. The target was to start producing stabilized crude simultaneously with the hot commissioning of the gas circuit. This part presents the overall results of adopting this approach. An assessment was carried out utilizing simulation software HYSYS prior to the startup. Post startup, actual field results were collected to analyze the effectiveness of N2 stabilization. N2 was proven to be an effective stripping medium in crude stabilization.
A Flow Network Model Based on Time of Flight for Reservoir Management
Authors: Sankaran Sathish , Sun Wenyue
Published: November 2020

Closed loop reservoir management is challenged with building reliable and fast predictive reservoir models to make field decisions. Traditional numerical simulation models can be difficult to characterize, tedious to build and calibrate, and at times computationally prohibitive for short term decision cycles in field applications. On the other hand, pure data-driven methods often lack physical insights and have limited range of applicability. For operational scenarios such as short-term production forecasting, waterflood optimization, production control and understanding major reservoir mechanisms, it is desirable to use a reservoir modeling methodology that is easy to build, history match, compute and interpret.

In this work, we propose to use a hybrid and efficient reservoir graph network (RGNet) modeling approach based on time of flight concept that can be built using routinely measured field measurements (such as pressure and rates) and can be used for real-time forecasts, scenario modeling, production optimization and control.

We propose a gridding method based on discretized time of flight for multi-well scenario with interference. It simplifies the 3D reservoir flow problem into a graph network representation that can be solved with any commercial reservoir simulator, which enables the RGNet model to be readily applied for various types of fluid physics. The parameters in RGNet model are obtained through assimilating observed data. The RGNet model has a very compact model representation that requires significantly less complexity compared with full-physics 3D models, which leads to very fast simulation. The efficiency of RGNet makes it appealing for applications where many simulation runs are needed.

We applied the proposed approach on SPE benchmark reservoir simulation models for single well, multi-well with interference and injector-producer pairs. The calibrated models are used to quantify uncertainty for production forecasting. In all cases, the range of uncertainty is reduced effectively and efficiently with data assimilation. The posterior RGNet models are also shown to provide reasonable estimates of reservoir and well drainage volumes. By virtue of the reduced complexity, the modeling methodology is highly scalable while still retains physical interpretability (in terms of pore volume and transmissibility). We also discuss the potential applications of the method such as reservoir connectivity analysis and well control optimization.

The proposed reservoir graph network (RGNet) modeling approach provides a unique and sustainable way to combine advanced analytics and physics to develop an explainable dynamic reservoir model that can be effectively used to understand reservoir behavior and optimize performance. The lightweight model lends itself naturally to fast computation that are required for scenario analysis and optimization.
New Generation NMR T1-T2 Logging and Integrated Formation Evaluation in Unconventional Reservoirs in China
Authors: Zhang Hao , WU JIAN FA , WANG YUE , ZHONG GUANG HAI , LIU QUN MING , LIAO MAO JIE , FANG TAO , GAO XIANG , ZHAO XIAN RAN , ZHAO HAI PENG , ZHAO JING KAI , WANG WEI , WEN JUE MEI , XIE TAO
Published: November 2020

The strong domestic need for oil in China requires further exploration in unconventional reservoirs, such as volcanic and shale oil reservoirs. Sweet zone identification is one of the most critical missions in formation evaluation. The complex mineralogy and low porosity in unconventional reservoirs result in little variations of resistivities from oil zones to water zones. The uncertainties in fluid typing lower the efficiency in finding the sweet zone.

In conventional reservoirs, nuclear magnetic resonance (NMR) logging based on cutoff analysis is the optimum choice for evaluating the porosity and pore geometry of hydrocarbon bearing reservoirs. However, the routine one-dimensional T2 measurement may not be sufficient for the formation evaluation in unconventional reservoirs, because of the overlap of signals of various fluids in the T2 space. This paper shows a new generation NMR tool with advanced measurements of continuous two-dimensional T1-T2. The T1-T2 measurements enable quantification of different fluids in the pores. Fluid typing is supported by the integration of other wireline logs, such as nuclear spectroscopy and dielectric dispersion.

Case studies are presented from volcanic and shale oil reservoirs in the Xinjiang Oilfield of PetroChina. In the volcanic reservoir case, a modern methodology based on the concept of 2D analytics for extracting signals from two-dimensional NMR T1-T2 measurements is proposed. An integrated workflow derived from wireline borehole image, spectroscopy, dielectric and NMR T1-T2 gives an insight into the fluid composition in the pore system. Besides accurate measurements of lithology independent porosity and pore geometry from NMR, clay bound water volume and total water volume derived from cluster volumetric analysis of NMR T1-T2 match well with those from spectroscopy and dielectric tools. It lowers the uncertainties of fluid typing in the volcanic reservoir where resistivities fail to differentiate water zones and oil zones. In the shale oil case, the reservoir producibility index (RPI) which takes the oil volume as a positive reservoir quality (RQ) index, and kerogen and bound hydrocarbon as negative RQ indexes is illustrated. It proves to be robust in sweet zone identification.

This paper discusses a novel application of a new generation NMR T1-T2 logging method in unconventional reservoirs, which helps the operator ascertain the potential of the reservoirs. The oil zones identified by the new method have promising oil productions. The workflow can also be applied to other unconventional plays in China.
Successful Water Shutoff Treatment of Fractured Carbonate Horizontal Well Under Aquifer Pressure Support
Authors: Hernando Louis , Martin Nicolas , Zaitoun Alain , Al Mufargi Hilal , Al Harthi Hamood , Al Naabi Ahmed , Al Subhi Khamis , Al Harrasi Mohammed Talib
Published: November 2020

Many horizontal wells in GCC (Gulf Cooperation Council) are producing from fractured carbonate reservoirs under aquifer pressure support. After water breakthrough, these wells suffer from high water cut rise due to water channeling through the fractures, inducing a strong and quick loss of well productivity. The wells being completed horizontal open hole, zonal isolation is very difficult to isolate the water producing zone. Moreover, mechanical water shut off like using liners or open hole packers is normally costly and challenging as well. Therefore, bullheading chemicals is often the only remaining option. The fractures being producing mixture of both oil and water, water shutoff in this type of well is very challenging.

To solve this problem, an original method was used consisting of microgel and gel injections. The strategy is to create a flow barrier deep in the fracture while preserving oil production from the matrix. The optimized procedure enables control of chemical placement by bullhead injection. Laboratory tests were conducted to optimize Microgel and gel chemistry (injectivity, gelation time and gel consistency/stability, return oil permeability).

The treated candidate was 530m long horizontal well and produced at around 600 bpd with water cut of 92%. Temperature and salinity were 62°C and around 100,000ppm respectively. Well behavior indicated existence of fractures along the wellbore.

The treatment consisted of 230m3 of successive Microgel/Gel injection at an average rate of 2.5 BPM. The treatment proceeded bullhead through annulus. WHP remained low throughout injection (150 psi). After curing time of 10 days for gel set, production was released with ramp up rate. The well, which was facing strong production decline, stopped declining, with a water cut drop of around 10%. Incremental daily oil rate was around 50 bopd with cumulative oil for the first 4 months of around 4500 bbls of oil.

This technology may have many applications in fractured carbonate fields and may lead to better oil potential from such high water cut highly fractured reservoir wells, with strong aquifer.