bluuebunny/crossref_metadata_2025 huggingface dataset:
Deployment of a Novel Soft Sensor in the Real Time Optimizer Architecture to Enhance the Integrity and Energy Efficiency of Sulfur Recovery Units
Authors: Dara Satyadileep , Khan Ibrahim , Al Jenaibi Eisa , Sengupta Subhendu , Goveas Vincent , Al Yahyaee Nawal , Ibrahim Salisu , Jagannath Anoop , Raj Abhijeet
Published: October 2022

Commercial analyzers for measuring the aromatics in the Claus furnace exit gas are currently not available and this leads to sub-optimal energy efficiency and poses asset integrity concerns. To address this problem a high-fidelity model is developed to function as a real time analyzer. Objective of this work is to incorporate the soft sensor in the architecture of Real Time Optimizer (RTO) to monitor the presence of aromatics in the Claus furnace exit stream.

The soft sensor is incorporated in the RTO server which provides the access to the plant operating data and the DCS (Distributed Control System). Soft sensor function in the RTO involves the following steps:

Soft sensor accesses the plant data and collects the needful input data for simulation Simulation software available in the RTO executes the softs sensor model simulation and generates the aromatics composition data Aromatics composition data is written to the DCS interface as a soft measurement Operators monitor the aromatic composition and accordingly adjust the fuel gas firing

Aromatic soft sensor is developed as a kinetic model, which is function of rate parameters of several key reactions of the Claus furnace. The kinetic model of the Claus furnace is incorporated in a process simulation model and catalytic convertors are simulated too. Model is validated with large plant data to show that model predicts furnace temperature within +/- 5% error and aromatics composition within +/- 5 ppm.

Simulation analysis shows that the furnace temperature can be decreased by at least 5 °C while ensuring no BTEX slip. Such change in furnace temperature leads to a reduction in fuel gas flow by ~200 Nm3/h, which translates to a monetary benefit of 0.5 million $/yr. Deployment of the soft sensor is currently in progress through engagement with RTO licensor.

To the best knowledge of authors, currently, there is no simulator in the market which can adequately model aromatics oxidation phenomena and predict the aromatic content in the furnace exit. This soft sensor being deployed is novel and first of its kind and expected to achieve a sustainable energy efficiency.
Multilateral Technology in the Middle East: 25 Years of Evolution
Authors: Kelsey Matthew , Fanchin Thomas , Janzen Micah , Alharbi Bandar
Published: October 2022

For a quarter of a century sustained technological advances in multilateral technology have enhanced economics and extended the production life of fields in the Middle East. This was accomplished by evolving to meet the demands of increasingly complex applications.

Over this history, multilateral applications have evolved from standard Level 2 and Level 4 dual-laterals to dual-laterals with intelligent flow control, intervention capabilities, and improved junction integrity. The use of multilateral technology can deliver a significant increase in reservoir contact compared to single horizontal wells. A dual-lateral well can deliver twice the reservoir contact while eliminating the drilling, casing, and cementing of an additional vertical wellbore section. Operators are implementing multilateral field strategies to reduce overall development cost, cycle times, and carbon footprint. Further benefits include delivery of wells and facility systems using fewer in-field construction hours at a lower baseline cost.

This paper discusses several multilateral installations in the Middle East over a 25-year period. It highlights the continuous improvement of multilateral technology used in the region by demonstrating how a multilateral well strategy reduces time-intensive operations by eliminating additional vertical wellbore sections and utilizing existing infrastructure. The case study will include discussion of workover intervention operations, completions, and lateral creation systems.

The application of a multilateral strategy is a proven method to reduce time intensive operations by eliminating additional vertical wellbore sections and utilizing existing infrastructure.

This paper will focus on the continuous improvement of multilateral technology to consistently meet challenges faced by operators in the Middle East region for over two decades. Wells originally drilled as standard Level 4 dual-laterals are now drilled and completed using intelligent flow control and, in some cases, Level 5 installations with pressure-controlled junctions.

The paper focuses on a region and the technology used to increase efficiencies, enabling the delivery of increased reservoir contact in less operational days. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.
Success Journey Designing the First Gas Storage Application
Authors: Fallatah Mohammed Khalid , Al-Sulmi Mohammed Othman
Published: October 2022

The objective of this paper is to shed light on the engineering optimizations and environmental initiatives adopted on Hawiyah Gas Storage facility process design; in order to build a robust facility that would support Saudi Aramco to continue being the industry pioneer and sustainable energy supplier, and meet Saudi Arabia decarbonization targets and minimize environmental footprint.

Hawiyah Gas Storage facility is one of the recent projects built to support the Kingdom energy sector by transforming the power generation industry from crude oil burning to natural gas by addressing the natural gas seasonal supply and demand variation. Eventually, it will enable reducing the greenhouse gas emissions by deploying numerous environmental initiatives, such as attaining lesser fugitive emissions valves, installation of flare gas recovery solution, implementation of relief valves leaks monitoring technology and the installation of ultrasonic gas leak detection systems.

As far for the engineering optimizations; several innovative ideas and case studies were considered in the facility preliminary and detailed design; including the optimization of the Inlet Facility Manifold and the Reproduction Facility Bypass Mode Optimization. The implementation of above-mentioned initiatives had resulted in significant improvements in the facility safe operability, maintainability, and indeed construability at site.

Throughout this paper, the deployed initiatives will be described in details along with the applied methodology to complete the study evaluation, and conclude wit the result and discussion.
Application of Dynamic Models to Generate Optimal Injection Distribution to Maximize Condensate Recovery at Partial Recycle Voidage Replacement Scenarios
Authors: Arianto Muhammad Ali , Karamessinis Aristeidis , Almaazmi Juma Mohamed , Almenhali Salem Saleh , Al Sayegh Ahmed Ali , Al Muntheri Hiyam Hamed , Almansoori Shamma Hala
Published: October 2022

The reservoir A is a gas recycle reservoir which has been in production since 2000 with a cumulative VRR (voidage replacement ratio) of 95%, aiming at maximizing condensate recovery through pressure maintenance above dew point. As market demand for lean gas increases, lower operating VRR is expected. Historically, the reservoir A operated at near full recycle mode with injection gas distributed equally among available injectors. An assessment has been done aiming to maximize condensate recovery with available gas to reinject. From the exercise, it was found that sectorial based prioritization alone is not enough due to presence of inefficient injectors which affect the injection efficiency for that particular sector.

Well operation priority for injectors is not as straight forward as it would be for producers, which can be ranked based on CGR (condensate gas ratio) to achieve maximum condensate production from time to time, because the effect of injection cannot be seen immediately, particularly in a large reservoir. On the other hand, there are limited studies on gas recycle reservoir injection optimization in the literature.

To tackle this challenge, the reservoir team developed a workflow methodology with wider applicability of injection prioritization in gas line drive injection patterns. This paper will describe how to utilize the reservoir simulation model to come up with optimum injection rate range per well through setting up an assisted optimizer.
Holistic Performance Review of Through-Tubing Sand Screen as Remedial Sand Control: Best Practices and Lesson Learnt from Past Installations in Offshore East Malaysia Oil Fields
Authors: Tang Catherine, Ye Lin , Yeap Wei Jian , Zulkifli M Zin , Bt M Jeffry Suzanna Juyanty , Minggu Nur’ain , Chin Alvin, Zhi Siang , Kong Randy, Zheng Chen , M Yusof Aqil , Liew Paul Lyan , Azman Muhamad Syazwan , Praveen Kumar , Yusnawannie Ilyas , Fahmi Amni Mustafaal Bakeri , B Zainul Zaimi
Published: October 2022

Low oil prices, coupled with operational challenges in offshore environment due to COVID-19 restrictions, have driven oil and gas operators to implement low-cost technological solutions to optimize fields’ production. For mature oil fields in offshore East Malaysia, sand production has become one of the onerous challenges that requires this approach. Sand production is known to adversely affect the well deliverability and it also contributes to safety concerns due to surface flowline leak and equipment failure. Hence, it is of upmost importance for operators to address the sand production downhole. To achieve this, through-tubing sand screens (TTSS) installation is opted due to its ease of installation and low-cost slickline operation. Although there have been many TTSS installations to date, there is still limited understanding of the factors that affect TTSS lifespan, and this has led to frequent TTSS changeout. Based on the operator's experience, TTSS lifespan can vary significantly across different wells ranging from just a few days to years of production. To improve the understanding of TTSS performance with the aim to increase TTSS longevity, a comprehensive study on potential contributing factors has been conducted by analyzing the past TTSS installations.

Over the years, there were more than 75 TTSS installations performed in oil fields offshore East Malaysia. Lookback analysis was conducted to evaluate the effectiveness of TTSS as remedial downhole sand control and investigate the factors affecting TTSS performance such as TTSS type, well production rates, TTSS deployment method, installation depth relative to perforation interval and well interruption frequency. Several criteria identified as the key performance indicators have been investigated to evaluate the performance of each TTSS installation, including the well flowing parameters, production uptime and sand production trend.

Thorough study across different TTSS installations has concluded that TTSS lifespan varies according to well properties and well operating parameters. This paper presents best practices and lessons learnt from past installations to predict and improve the mean time between failures (MTBF) for TTSS. Case studies for several wells have been scrutinized to highlight the learnings for further enhancement of TTSS lifespan. Additionally, recommendations for further research and development of erosion resistant TTSS technology are also discussed.
Accelerated FDP Reservoir Studies in Challenging Brownfields Utilizing Digital Could Technologies
Authors: Abdullah Anas Bin , Seah Yong Han , Chuah Stefanie Mei Mei , A Wahi M Saiful Nizam Bin
Published: October 2022

PETRONAS Baronia field is a mature oil field with over 45 years of production history, located offshore Sarawak, Malaysia. It consists of several vertically stacked clastic sandstone reservoirs, namely two major reservoirs: S and V2 reservoirs. Both reservoirs have been on production since 1970's with the production strategy evolving over the years to maximize recovery. Natural depletion, infill drilling, water and gas injection, and recently Immiscible Water-Alternating-Gas (IWAG) IOR/EOR strategies have been implemented. All these elements combined with the subsurface uncertainties pose challenges to history match and to conduct probabilistic forecast studies on the dynamic models. Conventionally, the development scenarios for subsurface investigation are limited due to finite computing resources. As PETRONAS is shifting its portfolios to develop more complex and challenging fields, the need for transformation in development concept evaluation is evident. This is key for proper risk and uncertainties quantification. The notable challenges are a) limited number of development scenarios being investigated, evaluated, and compared; b) limited software licenses and infrastructure availability; c) lack of data and decisions traceability.

These limitations are addressed by the PETRONAS LiveFDP digital transformation initiative commenced in 2019, through deployment of digital cloud technologies and solutions with scalable High- Performance Computing (HPC) environment. The cloud-based native and Petrotechnical applications enable remote work, ensure full data traceability and auditability, enable multi-realization ensemble analysis, and streamline the automated integration from the reservoir engineering ensemble workflow to economic analysis. Unlimited cloud computing power and licenses facilitate a broader spectrum of reservoir simulation cases to be investigated in a fast-tracked manner.

The cloud HPC infrastructure has shortened the history matching cycle from 3 months to 1.5 months. The team has also observed over 5 times speed enhancement on simulation run performance using cloud computing compared to virtual machine and on-premise infrastructure. Utilizing the cloud solutions and ensemble probabilistic approach, the team has achieved over 90% of history match quality through 300 realizations per ensemble running concurrently and completed within 2 hours. The optimized IWAG injection resulted in 2% (~1MMStb) higher oil reserves with 37% less gas injection and 40% shorter injection cycles. This has improved gas sales and prioritization in the field while also monetizing the oil

reserves. The ensemble analyses are then visualized using cloud-based data analytics system whereby key realizations and uncertainty parameters are further reviewed and highlighted across various disciplines collaboratively at real time.
AI Assisted Well Performance Prediction Based on Production Profiles Clustering
Authors: Badmaev Dorzhi , Mata Carlos , Braik Fahed , Saputelli Luigi Alfonso
Published: October 2022

Production forecast is an important part of field development planning using for business planning and economic evaluation of an oil and gas field. The conventional approach to production forecasting includes a bunch of methods from decline curve analysis to hydrodynamic modeling; however, these methods have certain limitations of use. The objective of the study is to investigate the possibility of application AI/ML methods in classification of wells by their historical behavior, and to use this information to predict performance of existing and future wells.

The core method of the tool is K-means clustering based on wells production profiles. There are several parameters which values have been taken at the certain time-steps, for example, oil rate, watercut, GOR, flowing bottom-hole pressure, etc. Each parameter's monthly record is combined with reservoir properties to define the input vector for each well. These vectors are assigned to a specific cluster number. The defined clusters can then be assigned to wells with shorter production history in order to predict their future performance. The proposed using pattern recognition of production is useful for the identification of possible neighbor wells influence and tunes production prediction.

The method was tested on an oil field in Abu Dhabi with over 50 wells. The results have shown that there is a good predictability for tested dataset. The obtained clusters identified the production performance in existing wells and the production forecast in the nearest future.

The method introduces a new approach to wells clustering based of production profiles only. The approach is tested on Abu Dhabi field first time and practical implementation of the method is showcased.

The limitation is that it is applicable to wells that have long production history with stable reservoir performance.
Calibration of Numerical Reservoir Models Permeability Using Correlated Seismic Amplitude with Pressure Transient Data
Authors: Shams Mohamed , El-Banbi Ahmed , Yehia Islam , Capra Laura
Published: October 2022

Effective reservoir characterization approaches aim to integrate all available and reliable sources of data to mitigate the effects of uncertainty of reservoir parameters and have a robust reservoir model(s). Reservoir permeability is one of the most critical, and usually, uncertain parameters in reservoir simulation models. The permeability model has a direct impact on production forecasts and consequently the economics of decisions made based on reservoir models. Having a calibrated permeability model is a challenging task. In most cases, the permeability model undergoes several modifications to achieve a history-matched reservoir model that honors the historical pressure and production data.

The objective of this work is to show a workflow that integrates two different types of data sources to help calibrate the permeability of reservoir models. The proposed approach relies on adjusting the permeability of reservoir models by integrating seismic amplitude values and data from wells’ pressure transient analyses. The seismic amplitude data in the vicinity of a candidate well is correlated with permeability obtained from recorded pressure transient data in a systematic way. The generated correlation is then applied to the entire reservoir model in order to calibrate the permeability value of each grid block in the model. The application of the proposed approach on actual field data is also presented. As a result, the seismic and pressure transient data both can make valuable contributions towards calibrating geo-cellular 3D reservoir models at their respective and different scales.
Multidisciplinary Data Integration for Artificial-Intelligence-Assisted Well Placement and Trajectory Design Optimization Under Uncertainty
Authors: Su Shi , Tahir Sofiane , Ghorayeb Kassem , Ramatullayev Samat , Garcia-Teijeiro Xavier , Mohamad Hussein Assef , Kada Kloucha Chakib , Mustapha Hussein
Published: October 2022

Infill well placement performed as part of field-development planning is traditionally performed by identifying areas of high remaining mobile hydrocarbons and good reservoir rock quality to be targeted. The identification of hotspots was also largely performed on single-model realizations and, therefore, not robust considering the reservoir characterization uncertainties. Increasing efforts were put into incorporating the uncertainties as a key element of the infill well placement workflow by computing probability maps to identify the hotspots with higher chances of success for infill production. The maps were still generated solely based on dynamic reservoir-simulation model results.

In this paper we present an intelligent workflow that integrates the opportunity index probability maps concept derived exclusively from dynamic reservoir simulation models, with drilling risk maps derived from drilling data analysis and completions quality maps derived from geomechanical studies, and artificial-intelligence-driven reservoir target classification. The integration provides more depth in the hotspot selection by identifying the most productive and feasible locations for infill drilling.

The locations are then used for well placement and trajectory design optimization. The well trajectories optimize factors in the hotspot locations, locations of existing drilling centers, surface topology for new drilling centers to be designed, numbers of available slots on each drilling center, and capital costs such as drilling economics and drilling center cost. Infill injection wells are placed in conjunction with the infill production wells either following a pattern-type of design or peripheral injection.

The designed wells are evaluated via an automated pipeline using reservoir simulation where the set of wells will be tested against the ensemble of realizations under uncertainty. A probabilistic approach is taken for the infill well performance and the economics evaluation for candidate screening and selection for the field-development plan optimization.

This approach provides higher confidence in the decision making through the early integration of drilling risks and geomechanics data, and provides a more robust assessment of the technical and economic performance of the proposed infill wells under uncertainty.

The solution combines various concepts including opportunity index, advanced ML methods for target identification, as well as multidisciplinary integration for well target identification. Well trajectory design evaluation considering both production and injection wells and the evaluation of the performance of the proposed candidates under uncertainty in this context provides more robust results under uncertainty compared to widely used industry practices that lack integration and uncertainty considerations.
Challenges in High Sour Gas Field Development and Non-Metallics Opportunities in Upstream Processes
Authors: Almuhammadi Khaled H. , Parvez Anwar Md. , Buali Mustafa S. , Salazar Vidal Oscar D. , Bukhamseen Ahmed Y.
Published: October 2022

High sour fields beyond 10% H2S concentration are considered one of the severe environments that require suitable tubular components and accessories in upstream environment to ensure sustainable production. Such environments represent a challenging operating envelop where durability and safety are the top concerns due to higher H2S concentration at a higher partial pressure and higher temperature (HPHT). The risk is amplified for the wells with higher than 10% H2S concentration, namely the High H2S wells, and those exceeding 25% H2S concentration which are typically labeled as Ultra-High H2S wells. Corrosion in gas operations can be aggravated in downhole where high H2S at higher temperatures pose additional challenges. Selection of proper material to ensure a sustainable well condition is one of the important elements for the development of these HPHT gas wells. Various challenges were identified, including the selection of cost-effective material which is capable of withstanding short and long term H2S and CO2 partial pressures as well as control generalized CO2 corrosion, sulfide stress cracking (SSC), and stress-oriented hydrogen induced cracking (SOHIC).

With the advancement of Non-Metallics (NM) materials in several applications across the O&G sector, it holds a promise to provide an alternative material solution in lieu of CRA alloy material for the HPHT downhole applications. NM materials are lightweight and they can be designed to withstand higher strength capability in addition to their outstanding corrosion resistance properties in a high H2S environment. Moreover, they can be engineered to fulfill the intended application due to their high design flexibility and durability. In the downhole applications, there is a number of NM products that have been implemented in sour environments, including sealants as well as downhole accessories and tools, where the list of NM technologies is considerably growing.

This paper highlights the concept of using NM products such as coiled tubulars, pressure control equipment and elastomers as well as the challenges on the development and deployment of these key components in high sour fields.
Operational & Social Challenges of Sour Gas Well Testing Operation in Brown Field
Authors: Ahmad Zeeshan , Al Hosini Abdullah Alhaj , Al Janahi Mohammed Ibrahim , Al Marzouqi Abdulla Mohammed , Siddiqui Muhammad Ali , Ahmad Mubashir , Agarwal Anubhav
Published: October 2022

Well testing operation of sour wells by flaring or flowing through existing pipe line network with limitations always consider as highly challenging in brown field. In this paper operational and social challenges considered during critical well testing operation during different phases.

For initial performance evaluation, completion and surface facilities were not designed as per expected well fluids specially in consideration of H2S, CO2 and elementary Sulphur. These wells located in congested developed field and special consideration regarding social risk analysis and mitigation were considered. Extensive H2S and SO2 dispersion modeling conducted to develop EPZ & EAZ for safe operation by utilizing latest safety equipment's.

Special scale treatment and down hole chemical injection adopted to cater tubing accessibility due to elementary Sulphur and other scale issues to improve flow assurance during well testing operation. Case study of condensate storge tank utilization with improved safety precaution will highlight the consideration of reservoir fluids for any well testing operation. High volatile Condensate handling at well site always be serious challenge and can be utilized with extensive HAZOP and better process safety controls.

Well intervention operation with High H2S for gas wells in presence of water aggravate corrosion and H2S cracking significantly for any type of metallic material. Special down hole plugs, wire line, E-line and sealing elements of pressure control equipment's designed and utilized during intervention operation along with utilizing of special chemical.

Well control is serious concern while flowing such wells due to catastrophic asset and environment impact. Special well control consideration needs to be in place for any well control scenario, this paper will cover all type of surface and subsurface consideration to improve the well & reservoir integrity.
Utilizing PulseJet Technology to Enhance Water Injectors Injectivity
Authors: Al Ruqaishi Abdullah Saud , Al Ghammari Ahmed , Ferdiansyah Erik , Al Harthi Najeeb , Plotnikov Alexey , Zazuliak Oleg , Inamov Noman , Hryhoruk Oleksandr
Published: October 2022

In one of north Oman matured carbonate water flood field (Block A), acid matrix stimulation treatments are usually performed by Well and Reservoir Management team (WRM) to enhance inflow performance. These treatments are deployed through Coiled Tubing Unit or bullheaded by pumping units. More than eighty percent (80%) of them are performed in water injection wells to remove near wellbore skin mainly due to calcium carbonate scale with hydrocarbon layer at the scale surface. 15% to 20% HCl simple acid recipe with or without chemical diversion are used as main fluid, with foam or gel acid as main chemical diverter. Recent treatments with 15% HCl have shown communication between treated injectors to nearby oil producers (short circuiting), suspected due to induced fracture by acid matrix stimulation treatment. Increasing in the demand of operational performance by eliminating unnecessary risk of inducing short circuiting between the water injector and oil producers has given birth to a new approach to enhance well injectivity.

The PulseJet technology trial is intended to remove near wellbore formation blockage using Surface Pulse Generator [5] without involving acid chemicals; hence it is expected to have less risk in inducing fracture to the formation. With no acid chemicals required, it means less HSE risk to the personnel. In addition, this technology uses existing energy of formation pressure, therefore can be applied in very low to nil injectivity, if formation pressure is high enough to remove the blockage. Low (less than 80 ltr/min well injectivity) to nil injectivity, usually cannot be efficiently treated with bullheading technique, therefore more expensive unit, i.e CTU, is required to deploy stimulation treatment in this type of wells. If this trial is successful, this can help to minimize CTU requirement hence will result in saving to the company.

This technology was trailed in 22 vertical water injectors where improvement of initial injectivity have been observed and 60% of them demonstrate sustained injectivity to more than 300 days. All treatments were performed safely with eliminating the exposure of mixing and pumping corrosive 15% HCl acid of 1500 m3. Most importantly, our wells did not experience any short circuiting with the oil producers.

This paper describes the Pulsejet technology implementation as alternative to the conventional methods CTU or bullheading matrix stimulation. The candidate selection and execution procedure will be discussed including the lessons learned during this technology trails implementation.
State-Of- The Art Corrosion Inhibitor Development to Mitigate Pitting Corrosion in the Presence of Elemental Sulfur and Poly Sulfides in Sour Oil and Gas Systems
Authors: Obeyesekere Nihal U. , Dickey Douglas C. , Wylde Jonathan J.
Published: October 2022

The effects of elemental sulfur on the corrosion of mild steel is a serious problem in the oil & gas industry costing millions of dollars annually in lost production and assets.

Mitigating the corrosive effects of elemental sulfur on mild steel in the oil and gas industry is a challenge and finding a viable solution would provide a more cost effective and safer working environment and as well as be environmentally conscious. Currently, there are no highly effective products for elemental sulfur corrosion in the marketplace.

More than fifty new chemical formulations were blended and screened by rotating cylinder electrode method (RCE). These formulations were tested in the presence of 0.1% elemental sulfur in mildly sour conditions. The promising candidates were identified and tested again in the presence of elemental sulfur under the same mildly sour conditions.

The most promising candidates from the initial screening were then subjected to rotating cage autoclave (RCA) testing for extended periods of time in the presence of 0.1% and 0.15% elemental sulfur. The general corrosion rates were calculated via weight loss and the metal surfaces were examined under a high-power digital microscope for pitting and localized corrosion.

A detailed analysis of the above testing yields promising results. The results from the testing show that formulations mitigate pitting in environments containing elemental sulfur. In less harsh conditions, such as low chloride brines or low CO2 environment, formulations seem to provide excellent protection against general corrosion while mitigating pitting due to elemental sulfur. In more extreme environments such as harsh brines with elevated chloride levels, high hydrogen sulfide and CO2 levels, the formulations mitigate pitting but need further development in inhibiting general corrosion The best product currently developed inhibits corrosion and pitting in the presence of elemental sulfur in various conditions and performs well against elemental sulfur in more aggressive sour systems. We are currently improving the performance against elemental sulfur and developing chemistries to mitigate polysulfide induced corrosion in sour systems.

This paper describes the development of effective inhibitors for corrosion and pitting in the presence of elemental sulfur under sour conditions. This study focuses more on pitting corrosion due to the corrosive characteristics of elemental sulfur than on uniform general corrosion. The general corrosion with the selected inhibitor was highly mitigated and was less than 3.0 mpy while yielding excellent protection against sulfur induced pitting.
A Successful Milestone Accomplishment of Sour Gas Well Testing Operation
Authors: Alsenaidi Shemaisa Ahmed , Albadi Mohamed Mubarak , Ahmad Mubashir Ahmad , Dike Nnamdi Ahmad , Alsaadi Noura Ahmad , AlHosani Abdulla Ahmad , Ahmad Zeeshan Ahmad
Published: October 2022

Submission Summary

A successful achievement by ASR ADNOC onshore started by accepting the challenge of testing Ultrasour gas wells. We are taping on additional reserve by carrying out the appraisal testing of sour gas wells with high H2S that contain H2S ranging from 20 to 40 % and CO2 11% approximately that is creating multiple challenges during testing and tie in the well. And due to high H2S compounded with extremely high temp and pressure the use of conventional material is not possible thus, creating multiple challenging while testing the gas wells in ADNOC Onshore fields. Another milestone of this project is evaluating the exotic material selection for sour wells, as well as HSE protocol modifications and utilizing the existing facilities in order to reduce the CAPEX & OPEX for the production of highly sour gas using the blending studies development.

So, this project is an example of success story that successfully managing the ultra-sour gas wells with high temp and pressure safely during drilling, tie-in and well testing operations. And once its potential is untapped the additional TCF (Trilliant Cubic Feet) gas will be available for the future generations.
Injection Profiling for Intelligently Completed Wells Equipped with Fiber Optics
Authors: Adil Mohamed , Santhirasekaran Lingies , Arief Tham Nabilla , Seabrook Brian
Published: October 2022

Injectors with intelligent well completions are installed in a geologically complex reservoir setting to inject fluid into multiple zones. For effective reservoir management, it is imperative to know the injection profile along the wellbore and to detect injection defects. Distributed Temperature Sensing (DTS) fiber installed along the length of the well provides high spatial resolution and high frequency temperature data. This paper presents a methodology to estimate zonal-level fluid injection volumes using these DTS measurements. When cold fluid is injected into a hotter reservoir, the region near the wellbore cools down. When injection ceases, the wellbore region slowly warms back to the far field geothermal temperature. The proposed methodology models heat transfer in the radial direction during this warmback period using 1-D energy equations. The model is tuned to DTS data from the warm-back using regression techniques applied independently at each depth. Only the middle time region (MTR) of the warmback is considered for the model since, at early times, we have thermal effects from adiabatic expansion and, at late times, the 1-D modeling assumption is no longer valid. This approach is analogous to the MTR concept often used in pressure transient analysis. Model parameters at each depth are related directly to the volume of fluid injected in the corresponding zone and their relative values can be used to allocate injected fluid volumes. The conventional use of the warm-back model looks at the relative rate that individual zones warm up during a shut-in following cooler water injection to estimate the relative volume of fluid injected into that particular zone. This conventional methodology considers all the data points from warm-back to fit the model. The improved method presented in this paper acknowledges that the early time region (ETR) and late time region (LTR) are not really addressed in the model. Rather it carves out the information by modeling the middle time region (MTR). An alternate approach presented looks at the asymptotic behavior of the middle-time warm-back to infer the cumulative injection volume in each zone. A few test cases are presented comparing the results of the various methodologies and the insights we gain from this analysis. Injection logging is an expensive, conventional method for injection profiling. With the help of fiber technologies and methodologies presented in the paper, we can achieve an accurate understanding of injection profiling without the need for logging. Additionally, we show a methodology where subsequent analysis of warmback at two or more shut-in times gives insight into the injection profile when the original geotherm is disturbed by prior injection or not well known.
Alternatives to 28% Chrome for Production Tubing in Super-Giant Mediterranean Deep Water Gas Field, Zohr Field, Eni–Petrobel
Authors: Ibrahim OMAR Yehya Abou Elseoud , Gabr Waleed , Kortam Mostafa Mahmoud , Abdelrahman Mahmoud , Moawed Mahmoud , Elmasry Hossam
Published: October 2022

Zohr field was discovered in 2015 by the Italian energy company Eni and is the largest ever natural gas found in the Mediterranean Sea, with around (30 trillion cubic feet) total gas in place. Belaim Petroleum Company (Petrobel) (JV with ENI) is the Egyptian Petroleum Corporation arm and the owner of the project. Production started in December 2017 and since then 18 wells have been drilled for production.

This paper describes the criteria for material selection of the production strings for Zohr’s deep-water gas producers and how pre-tested and approved cost-effective alternatives are available for such a top-class project. The paper details the qualification and deployment of glass reinforced polymer (GRP) Lined Tubing as an alternative to 28%Chrome tubing, including the testing work that has been performed, and the operational aspects of running the referred-to alternative in several deep-water projects.

The choice of Duoline lined tubing results from the need for a cost-effective solution delivering the same operational requirements of 28% Chrome production strings. And since the Duoline GRE system will be integrated with the steel tubing therefore this system has to be previously fully approved and certified by the manufacturing mill of the lined tubing so there would be not even minor modifications to the specifications and the sealing performance of the premium connections and tubing body.

The paper indulges into describing the laboratory tests and the field experiences of the Duoline Lined tubing system in various fields globally, where this system has been tested in severe operating conditions with elevated levels of H2S, CO2, Salinity, dissolved Oxygen conditions to investigate the capability and service limits of the fiberglass liner at different temperatures. In addition to mentioning the erosion tests that were performed, mechanical tests such as pressure loop and make & break tests, how these various tests ended with good results and its comparison to the exotic high chrome joints performance.

This fiberglass lined tubing system has been applied in gas production wells since the 1980s, and ENI has been utilizing this technology in their production and water wells since 2005 in the north Africa, middle east, Kashagan regions and Norway offshore wells. On the other side, the technology has been successfully used world-wide in more than 55,000 wells since 1960s in various applications besides gas production strings.

The paper will present the past experience of ENI with fiberglass lined tubing, the laboratory tests, the field experiences, the economic evaluation of implementing this system in such a high-profile project, In addition to the pre-qualifications performed on this system by the OCTG mills and approvals granted to integrate this technology with the patent premium connection joints.
Novel Organically Modified Nanoparticles Stabilized Emulsified Acid Paves Way for Productivity Enhancement in High Temperature Gas Reservoirs
Authors: Kalgaonkar Rajendra A , AlJama Majid , Cairns Amy J , Alali Eyad
Published: October 2022

Well stimulation of carbonate reservoirs is conventionally associated with the using of strong mineral acids such as hydrochloric acid (HCl). However, the heterogeneity of the reservoir as well as the fast reaction rate of HCl with the rock will lead to face dissolution rather than achieving deeper wormholes or longer fractures. A commonly used approach to slow down the acid/rock reaction rate is through the use of acid-in-oil emulsions. Unfortunately, the thermal stability of the emulsified acids is significantly impacted at high temperatures (+300 °F), which will result in poor penetration of the reservoir, thus reducing the treatment effectiveness.

This paper showcases the development and successful field application of an enhanced emulsified acid system for stimulating high-temperature carbonate reservoirs. The new system utilizes organically modified nanoparticles with the emulsified acid to form a solid stabilized emulsion. The unique morphology of the nanoparticles along with their selective organic modification facilitates formation of a high temperature stable emulsified acid system with lower viscosity compared to conventional emulsified acids. The low viscosity reduces surface pumping pressures leading to higher pumping rates for deeper reservoir penetration. The new system can work with HCl concentration up to 28% and temperatures up to 325 °F.

We present here the systematic developmental study and field trial results for the organo-modified nanoparticles stabilized emulsified acid system, targeting high temperature carbonate gas reservoirs. Several laboratory performance tests were judiciously undertaken to compare the performance of the new emulsified acid with conventional systems. Experimental studies including rheological characterization, thermal stability, corrosion mitigation and formation damage profiling are reported. The new emulsified acid displayed lower viscosity, enhanced stability at high temperatures, corrosion loss within industry acceptable limits, superior stimulation effectiveness and minimal formation damage compared to conventional emulsified acid. Stimulation treatments using the enhanced emulsified acid showcased excellent flowback performance with no reservoir damage.

The new organo-modified nanoparticles based emulsified acid system not only demonstrated enhanced temperature stability, but also minimized the surface treating pressure facilitating higher pumping rates and deeper reservoir penetration resulting in excellent stimulation of carbonate reservoirs.
Assessing 3D Bedding Plane Effects on Well Performance in a Field-Scale Unconventional Reservoir Model Using EDFM
Authors: Leines-Artieda Joseph Alexander , Fiallos-Torres Mauricio Xavier , Useche Franklin , Fonseca Rahul-Mark , Mahmoud Salah El din , Alqaydi Maryam , Alharthi Amena , Al Hashmi Abdulla , Ramsay Travis , Al Bannay Aamer , Song Xueling , Yu Wei , Miao Jijun
Published: October 2022

Bedding-plane slip effects during hydraulic fracturing have recently gained interest in unconventional plays due to their influence in hydraulic fracture growth in vertical and horizontal directions. However, most of the current workflows cannot fully model field-scale sub-horizontal orientation of bedding planes because of complications with gridding techniques, or due to simplifications related to the use of 2D models. These challenges have motivated the assessment of 3D bedding plane interactions on well performance using the embedded discrete fracture model (EDFM) technology for field case scenarios.

An efficient hydraulic fracture propagation model is used to model hydraulic fracture growth in the presence of bedding layers. The model captures shear slippage at the bedding layer interfaces and corrects the calculated stress intensity factor to account for height containment. A hydraulic fracture model, constrained by geomechanical information, is built in a corner point grid. Resulting hydraulic fracture geometries and identified bedding layer fractures are transferred to EDFM by using a 3D bedding plane generator, which places sub-horizontal polygons across the well trajectory, honoring its orientation and geometry. To locate the spatial position of bedding layers, geostatistical constrains, core analysis and petrophysical interpretations – including well image logs – can be taken into account. Lastly, a reservoir simulation model is built to evaluate the effects of bedding planes on well performance.

3D effects of bedding planes in a shale gas reservoir were captured in a field case scenario using numerical models. Higher contribution to production was observed in the results of this study. The main reasons are larger fracture lengths generated along the pay zone caused by bedding plane influence in the fracture propagation process and shear slippage along bedding plane fractures, which create a larger effective conductive surface area. When modeling bedding planes, computational efficiency is substantial due to the EDFM method, preserving spatial orientation and geometry of each bedding plane.

Direct assessment of bedding plane properties is provided, which highlights the importance of capturing their interactions with hydraulic fracture growth and well performance. A seamless integration of bedding plane models can be achieved in an efficient workflow that provides key lessons for future fracture design and well spacing optimization.
Integrated Concept Analytics and Development Optimization Under Uncertainties
Authors: Shao Yufen , Li Jizhou , Seow Ming–Jung , Zhu Yuzixuan , Guo Yuanyuan , Pradhan Daman , Malpani Deepak , Furman Kevin
Published: October 2022

Decision-making complexity in the oil and gas industry has risen dramatically in recent years, especially in consideration of uncertainties related to geopolitics, policies, marketing, subsurface resources etc. To enable decision making with the best quality opportunities and projects, we are developing an integrated suite of machine augmented mathematical technologies to recommend holistic decisions for concept selection and development planning under uncertainties. Our ongoing technology development is progressing a set of prototypes and use cases including: 1) AI-based uncertainty handling technologies aiming to detect uncertainties, quantify impacts, and translate to influence factors for decision-making (e.g., IRR, cost); 2) Decision-driven surrogate reservoir models approximating subsurface dynamics to enable rapid concept screening; 3) a set of mathematical optimization-based decision models in the form of mixed-integer linear programs (MILP) to provide solution alternatives to address different business challenges under uncertainties. We demonstrate that the use of systematic technical applications combined with human interaction can improve the decision quality significantly by considering all influence factors, searching through the entire decision space, and recommending a range of alternatives for business users to consider with minimal bias. These technologies have been designed to plug into existing processes and platforms to accelerate technology adoption and usage.