bluuebunny/crossref_metadata_2025 huggingface dataset:
STEP Change in Preventing Stuck Pipe and Tight Hole Events Using Machine Learning
Authors: Bahlany Salah , Maharbi Mohammed , Zakwani Saud , Busaidi Faisal , Benvenuti Ferrante
Published: December 2021

Wellbore stability problems, such as stuck pipe and tight spots, are one of the most critical risks that impact drilling operations. Over several years, Oil and Gas Operator in Middle East has been facing problems associated with stuck pipe and tight spot events, which have a major impact on drilling efficiency, well cost, and the carbon footprint of drilling operations. On average, the operator loses 200 days a year (Non-Productive Time) on stuck pipe and associated fishing operations.

Wellbore stability problems are hard to predict due to the varying conditions of drilling operations: different lithology, drilling parameters, pressures, equipment, shifting crews, and multiple well designs. All these factors make the occurrence of a stuck pipe quite hard to mitigate only through human intervention.

For this reason, The operator decided to develop an artificial intelligence tool that leverages the whole breadth and depth of operator data (reports, sensor data, well engineering data, lithology data, etc.) in order to predict and prevent wellbore stability problems.

The tool informs well engineers and rig crews about possible risks both during the well planning and well execution phase, suggesting possible mitigation actions to avoid getting stuck. Since the alarms are given ahead of the bit, several hours before the possible occurrence of the event, the well engineers and rig crews have ample time to react to the alarms and prevent its occurrence.

So far, the tool has been deployed in a pilot phase on 38 wells giving 44 true alarms with a recall of 94%. Since mid-2021 operator has been rolling out the tool scaling to the whole drilling operations (over 40 rigs).
First Use of Novel High Temperature Water-Based Reservoir Drilling Fluid to Access Depleted Deepwater Reserves
Authors: Morrison Alexandra Clare , King Conan , Rodrigue Kevin
Published: December 2021

A combination of divalent base brine and high wellbore temperature presents significant challenges for high density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Non-aqueous drilling fluids are thermally stable but complete removal of the filtercake is challenging and this can lead to formation damage. This paper describes the qualification and first deepwater drilling application of a unique aqueous reservoir drilling fluid at temperatures above 320°F.

A high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and a solids-free screen running fluid (SF-SRF) were designed, both utilizing the same novel synthetic polymer technology. Calcium bromide brine was selected for use to minimize the total amount of acid-soluble solids in the drilling fluid. A comprehensive qualification was undertaken examining parameters such as rheology performance across a range of temperatures, long-term stability, fluid loss under expected and stress conditions (16 hours at 356°F), production screen test (PST), and various fluid-fluid compatibility tests. Return permeability tests were conducted on the final formulations to validate their suitability for use.

The synthetic polymer technology provided excellent rheology, suspension, and fluid loss control in the fluid systems designed in the laboratory. To prepare for field execution multiple yard mixes were performed to verify the laboratory results on a larger scale. Additionally, a flow loop system was utilized to evaluate fluid performance under simulated downhole temperature and pressure conditions before field deployment. The final high temperature drilling fluid as designed provided rheological properties that met the necessary equivalent circulating density (ECD) requirements while drilling the reservoir. The fluid loss remained extremely stable and there were no downhole losses despite the depleted nature of the wellbore. Production screens were run straight to total depth (TD) with no wellbore stability issues after a three-day logging campaign.

High temperature aqueous reservoir drilling fluids have historically been limited by the lack of suitable viscosifiers and fluid loss control additives. This paper outlines the design, mixing and logistical considerations and field execution of a novel polymer-based reservoir drilling fluid.
Enhanced Productivity in Horizontal Open Hole Completion Using Integrated Dynamic Diversion Acid Squeeze Technique in Highly Depleted Well: Successful Application in West Kuwait Field
Authors: Al-Sabea Salem , Abu-Eida Abdullah , Patra Milan , Haider Yousef , Al Qattan Hasan , Khandelwal Nakul , Matar Khaled , Chawla Sapna , Gaur Rishika
Published: December 2021

The Minagish field in West Kuwait is a high potential field which poses several challenges in terms of hydrocarbon flow assurance through highly depleted tight carbonate intervals with uneven reservoir quality and curtailed mobility. These conditions have shifted the field development from vertical to horizontal wellbore completions. Achieving complete wellbore coverage is a challenge for any Matrix Acid treatment performed in a long openhole lateral with disparities in reservoir characteristics. The fluid will flow into the path of least resistance leaving large portions of the formation untreated. As a result, economic Acid treatment options dwindle significantly, thus reservoir stimulation results are not always optimum.

A multistage acid stimulation technique using Integrated Dynamic Diversion (IDD) has been performed in a West Kuwait field well. The process uses active fluid energy to divert flow into a specific sweet point (high pressure point) in the lateral, which can pinpoint and precisely place acid treatment at the desired location. The process uses two self-directed fluid streams: one inside the pipe and one in the annulus. The process mixes the two fluids downhole with high energy to form a consistent controllable mixture. The technique includes pinpoint fluid jetting at the point of interest, followed by customized foamed HCL acid systems employed for improving individual stage targets in depleted reservoir. The IDD diversion shifts the acid treatment to unstimulated areas to create complex wormholes which increase reservoir contact volume and improve overall conductivity in the lateral. The kinetics and chemical diversion of the IDD methodology are highly critical to control fluid loss in depleted intervals and results in enhanced stimulation.

The application of the IDD methodology is a fit-for-purpose solution to address the unique challenges of openhole operations, formation technical difficulties, high-stakes economics, and untapped high potential from intermittent reservoirs. By utilizing this application in one continuous operation, the use of chemical diverters, straddle packers and mechanical plugs for selective treatment in open hole is eliminated, making this multistage completion technology economical for these depleted wells.

The paper presents results obtained after stimulating multiple zones along the lateral and describes the lessons learned in the implementation of this methodology. Going forward, the methods described, which can be considered a best practice for application to similar challenges in other fields. Proper candidate selection, optimum completion tools, and the fluid combination of in-situ gel-based diverter used to temporary plug the acid stimulated zone and foamed acid created an increase in the oil production of 430 BOPD.
Quantifying the Tangible Value of a Smart Field Asset Implementation Leveraging on Digital Technology and Automation, Taking into Account the Intangible Value Element
Authors: Ibrahim ElFadl Z. , Al Hendi Mariam A. , Al-Qamzi Abdulla , Ballaith Nasser A. , Al Hosani Dr Esra Y. , Al Wehaibi Sara A. A. M. , Muhamed Salim Muzahidin , Traboulay Ian
Published: December 2021

The value calculation for a new digital and innovative technology is often requested by the executive management to justify the cost required for the implementation and maintenance of the technology. The value is normally segregated into a tangible and intangible value that correspond to a quantitative and qualitative description of those value elements.

As part of the Digital Oilfield (DOF) assessment, the solution value has been defined using two approaches. Firstly, qualitative value is described using a "FEATURE_BENEFIT_VALUE" model. The qualitative value elements have been grouped to align with the company strategic pillars to achieve its vision. Secondly, the quantitative value has been estimated using an NPV model. It estimates the value of the complete digital solution (combined investment for all domains) being proposed for the Asset.

The model estimates the net present value (NPV) of the expected Asset investment in digital enablement and digital capability as defined in the assessment report. Net cash flow graphs are also calculated. The approach used is to calculate an NPV for a GO-NOGO decision. Therefore, a conservative estimate of NPV is made with the mind-set that if even being conservative, the NPV clears the company's hurdle rate for such projects, then the decision to invest is undertaken. Sensitivity analysis has been performed using conservative estimates of production gain enabled by digital and conservative oil prices.

The paper will detail out the approach for the value quantification of a DOF solution that will also correspond to the industry guidance. Example on how the value is calculated will also be outlined.
Experimental Methods for the Evaluation of the Efficiency of an Innovative Sulfur-Dissolving Product in HP-HT Conditions
Authors: Maffeis Ivan , de Angelis Alberto Renato , Guernelli Riccardo , Croce Ettore , Romano Luigi
Published: December 2021

During production from sour gas reservoirs, precipitation of elemental sulfur can take place in production tubing, resulting in plugging of the well and stop of production. Injection in tubing of products devoted to dissolving sulfur can be an efficient solution for plug removal and production restoring.

Traditionally, organic solvents (like toluene) are employed for solid sulfur dissolution. In the present work, experimental investigations have been performed on a particular innovative liquid product designed as active phase for wellbore injection or near wellbore applications.

The analyses about the behavior of the considered product were conducted at HP-HT conditions. For this purpose, PVT laboratory equipment was employed, being able to reproduce the conditions of interest for the formation of elemental sulfur plug in well. An important preliminary optimization phase on the experimental setup was necessary to assure the correct management of studied liquid substance and solid sulfur.

Integration of main outcomes with other kind of analyses allowed to depict a complete representation of the behavior: microscopy analysis of the liquid phase and high-resolution tomography of solid sulfur before and after the interaction were employed.

A key point of the experimental characterization is the reproduction of significant involved phenomena. A preliminary effort was necessary for reproducing the realistic crystal form expected during the precipitation of solid sulfur in well.

The dissolution efficiency of the liquid product is evaluated by observing its physical interaction with sulfur in a HP-HT cell. Particular attention was paid to correctly handling employed substances at the considered pressure and temperature conditions. A detailed description of the optimized equipment used in laboratory is provided.

Several dissolution tests have been conducted at different temperature and pressure conditions, aiming to observe the dependence of the dissolution efficiency on the thermodynamic parameters.

A visual qualitative analysis was performed on both the liquid product and the solid plug, before and after the interaction in cell. This allowed to deepen the comprehension of the dynamics of sulfur dissolution, which takes place not only from the top face of the plug, but also from preferential paths (fractures) present inside the plug itself. The presence of sulfur crystals dispersed in the liquid product after sampling from the cell is also evident at the end of the tests.

The studied novel sulfur-dissolving liquid active phase is a candidate for remedial job injection at well in case of plugging due to solid elemental sulfur precipitation. The analyses here presented allowed to characterize the dissolution potential of this product. An optimized workflow was designed, including different kind of experimental disciplines.
Unleashing the Potential of Relative Permeability Using Artificial Intelligence
Authors: Shah Abdur Rahman , Ghorayeb Kassem , Mustapha Hussein , Ramatullayev Samat , Droubi Nour El , Kloucha Chakib Kada
Published: December 2021

One of the most important aspects of any dynamic model is relative permeability. To unlock the potential of large relative permeability data bases, the proposed workflow integrates data analysis, machine learning, and artificial intelligence (AI). The workflow allows for the automated generation of a clean database and a digital twin of relative permeability data. The workflow employs artificial intelligence to identify analogue data from nearby fields by extending the rock typing scheme across multiple fields for the same formation.

We created a fully integrated and intelligent tool for extracting SCAL data from laboratory reports, then processing and modeling the data using AI and automation. After the endpoints and Corey coefficients have been extracted, the quality of the relative permeability samples is checked using an automated history match and simulation of core flood experiments. An AI model that has been trained is used to identify analogues for various rock types from other fields that produce from the same formations. Finally, based on the output of the AI model, the relative permeabilities are calculated using data from the same and analog fields. The workflow solution offers a solid and well-integrated methodology for creating a clean database for relative permeability. The workflow made it possible to create a digital twin of the relative permeability data using the Corey and LET methods in a systematic manner. The simulation runs were designed so that the pressure measurements are history matched with the adjustment and refinement of the relative permeability curve.

The AI workflow enabled us to realize the full potential of the massive database of relative permeability samples from various fields. To ensure utilization in the dynamic model, high, mid, and low cases were created in a robust manner. The workflow solution employs artificial intelligence models to identify rock typing analogues from the same formation across multiple fields. The AI-generated analogues, combined with a robust workflow for quickly QC’ing the relative permeability data, allow for the creation of a fully integrated relative permeability database. The proposed solution is agile and scalable, and it can adapt to any data and be applied to any field.
Modeling a Novel Approach to Delay the Water Breakthrough in Gas Cap Wells Using Smart Completions: Case Study Onshore Abu Dhabi Field
Authors: Ojha Aditya , Al Hosani Mariam Ahmed , Al Bairaq Ahmed Mohamed , Mengal Salman Akram , Mohamed Ihab Nabil , Abdullayev Azer , Roopal Allen
Published: December 2021

This paper presents modeling a novel approach to determine the impact of implementing smart completions on water injectors located near the periphery of the gas cap and on gas producing wells situated in the gas cap of a giant Middle East onshore field. The objective of the study is to thoroughly investigate different smart completion designs which can effectively delay water breakthrough on the gas cap wells.

The study investigates the impact of adding smart well completion designs like ICD and AICD valves in delaying water breakthrough. The first phase involves adding smart completions to only water injectors. Sensitivity runs on several downhole completion design scenarios are conducted using a commercial near wellbore simulator and the optimal downhole completion design is implemented on a dynamic model and its impact is examined using a reservoir simulator. In the second phase, this approach is applied only for gas producers, and in the third phase the smart completions are simultaneously applied to both water injectors and gas producers.

The detailed study has revealed that the uncertainties and time involved in selecting optimal ICD design and placements could be reduced considerably by using an optimized workflow. The workflow uses a carefully designed process of using the outcomes from near wellbore simulators and incorporating the results in the actual full field dynamic models to assess the field level impacts.

When compared to the bare foot design, ICD and AICD valves showed better performance in delaying water breakthrough from the gas wells.

This paper provides a detailed study on the impact of different smart completions on delaying water breakthrough in gas production wells. The study also investigates how a uniform injection or production profile can be produced using different smart completions. Uniform injection and production profiles limit water fingering in the reservoir, and thereby delay water breakthrough caused by the flow of water through high permeability channels.
A Case-Study for the Reduction of CO2 Emissions in an Offshore Platform by the Exploitation of Renewable Energy Sources Through Innovative Technologies Coupled with Energy Storage
Authors: Joseph Epoupa Mengou , Chiara Gambaro , Andrea Alessi , Andrea Terenzi , Michela Vecchione , Marco Binaschi , Salvatore R Di Salvo , Anglani Norma
Published: December 2021

Energy storage is entering in the energy distribution supply chain due to the global goal of achieving carbon neutrality in human activities, especially those related to energy production. Renewable energies integrated with energy storage play an important role in this framework [1].

The purpose of the study is to evaluate through simulations the impact of new renewable energy technologies in a microgrid to minimize fossil fuels consumption. The case study considers a hybrid microgrid including: a gas microturbine, organic photovoltaic panels (OPV), a point absorber wave energy converter, a vanadium redox flow battery and a load. The microgrid is placed in an offshore hydrocarbon plant near the northern coast of Australia.

Firstly, Australian meteorological data have been studied and three seasons identified (named ST1, ST2 and ST3). Then a correlation has been established between meteorological data and OPVs performances, analyzing data collected on OPVs panels installed. This relationship has been used to assess OPVs potential production at the site of interest. Similar correlation was made between the performances of a wave energy converter placed in the Adriatic Sea and the wave power matrix, to determine a suitable power data reference for the potential production of a wave energy converter to the Australian coast.

Finally, the behavior of the microgrid was modeled.

Different scenarios have been considered and the best one with optimal meteorological conditions enables lead to drastically decrease of the use of gas micro turbine resulting in lowest CO2 emissions. In fact, the consumption of natural gas has been summarized as follow:

Season 1 (ST1): during this season the load is entirely fed by the renewable sources and by the battery, with consequent zeroing of the daily consumption of natural gas.

Season 2(ST2): the battery is charged from 09:00am to 07:00pm with the exceeding power from the renewable sources. This configuration involves a daily natural gas consumption of 10.73 Sm3/d, which is equivalent to 987.16 Sm3/ ST2 (accounting for 92 days).

Season 3(ST3): the battery is charged from 09:00am to 07:00pm with the exceeding power from the renewable sources. This configuration involves a daily natural gas consumption of 6.58 Sm3/d, which is equivalent to 1006.74 Sm3/ ST3 (accounting for 120 days). The avoided CO2 emissions are 2062 tons/year.

This case study showed how the new renewable technologies, such as organic photovoltaics and wave energy converter, coupled with a long duration storage system, can be conveniently applied in sites with limited space for the decarbonization purpose of an offshore platform.
Remote Drilling Solution Delivers Consistency with the Use of an Automated Drilling Director: Case Studies from Kuwait
Authors: Farhi Nadir , Marck Julien Christian , Sanyal Aniket , Abdel Samie Mohamed Ahmed , Eldemerdash Moataz Mahmoud , Safar Ali Hussein , Al-Khaja Mohamed Jassem , Malik Abdullah Ahmad , Mohamed Jassem Ali , Haddad Hassan Salman , Al-Mulairi Mohamed Mansour , Alotaibi Youssef Eid , El-Enezi Sager Hammad , Alotaibi Youcef Eid , Jamal Jamal Ahmad , Rathuri Sushil Kumar
Published: December 2021

The Automated Drilling Director, a software application for drilling automation, integrates a physics-based model of the drilling system with machine learning and optimization algorithms to project the well path, monitor collision risk, manage vibrations, and control steering in real time automatically. With "intelligent" rotary steerable systems (RSSs), these steering decisions can be downlinked directly to the tool, thus, fully closing the loop around steering decision-making. Implementation of the Automated Drilling Director within a remote drilling center (RDC) enables the drilling operations to be conducted remotely and effectively with less rig site personnel. The resulting decisions are consistent and reliable, while a team of subject matter experts (SMEs) monitor the operations to optimize well assets, ensuring that the pre-job design of service (DoS) is executed properly. The validation of this innovative technology and approach in Kuwait, amongst others, opens the door to a new way of doing business, where resources, experience, and data are combined in the most efficient manner to improve consistency, as well as to maximize the value of the operators’ assets.
Role of Well Logs and Seismic Data Conditioning in Improving the Imaging of Complex Reservoirs from Abu Dhabi
Authors: Obaid Khalid , Aamir Muhammad , Nafie Tarek Yehia , Aly Omar , Krissat Widad , El-Mawla Walid Abd
Published: December 2021

Rock physics/seismic inversion is a powerful tool that deliver information about intra-wells rocks elastic attributes and reservoir properties such as porosity, saturation and rock lithology classification. In principle, inversion is like an engine that should be fueled by proper input quality of both seismic and well data.

As for the well data, sonic and density logs measure the rock properties a few inches from the borehole. Reliability of sonic transit-time and bulk density logs can be affected by large and rapid variation in the diameter and shape of the borehole cross-section, as well as the process of drilling fluid invasion. The basic assumption for acoustic well logs editing and conditioning is to use other recorded logs (not affected by bad-hole conditions) in a Multivariate-Regression Algorithm. In addition, Fluid Substitution was implemented to correct for the mud invasion that affects the acoustic and elastic properties based on the PVT data for fluid properties computation. The logs were then quality checked by multiple cross-plotting comparisons to the standard Rock-physics trends templates.

As for seismic data, there are several factors affecting the quality of surface seismic data including the presence of residual noise and multiples contamination that caused improper amplitude balancing. Optimizing the seismic data processing for the inversion studies require reviewing and conditioning the seismic gathers and pre-stack volumes, guided by a deterministic seismic-to-well tie analysis after every major stage of the processing sequence. The applied processes are mainly consisting of Curvelet domain noise attenuation to attenuate residual noise. This was followed by high resolution Radon anti-multiple to attenuate residual surface multiples and Extended interbed multiple prediction to attenuate interbed multiples. In addition, Offset dependent amplitude and spectral balancing were applied to maintain the seismic amplitudes fidelity.

This paper will illustrate a case from Abu Dhabi where data conditioning results improved the Hydrocarbon saturated carbonates vs brine saturated carbonate and the lithology predictions, leading to optimizing field development plans and drilling operations.
Bond Strength Testing and Simulation for Grouted Pile/sleeve Connections in Aged Structures
Authors: Rao Mohan Aita Raja Srinivasa , Omar Tarek , Sarkar Anjan Amulyaratan , Roy Michael , Sun Xing , Lunn Rachel , Wu Huan
Published: December 2021

Recently the old accommodation platform (OAP) was decommissioned in Offshore Abu Dhabi. This platform was founded on four legs with piles inside and duly grouted inside pile and annulus. The main objective of this to carry out bond strength tests and finite element (FE) analysis for retrieved OAP grouted samples to investigate if any ageing effect on the bond strength of the grouted pile/sleeve connections for aged offshore structures. Nine Sleeve/Pile samples of varying lengths from 240mm to 1200mm were extracted for testing from the decommissioned platform. Dimensional analysis was carried out to assess the thickness loss and eccentricity. A bespoke testing rig with the maximum load capacity of 15,000kN was built at TWI Ltd. to perform bond strength tests. Finite element (FE) simulation of the testing was carried out and compared to the test results to calibrate and fine-tune material constitutive behaviour parameters and interfacial (friction and bond) parameters. Specimen measurements revealed a significant scatter in annulus grout thicknesses of various sleeve/pile specimens with maximum variations of up to 52%. These results indicate that pile alignment is strongly variable. Shear keys in the form of steel rings welded alternately onto the leg's inner surface and the pile outer surface providing mechanical resistance to relative sliding of the grout between the two bodies. The testing results shown that the ultimate loads varied significantly among various specimens, ranged between 9920kN for 1m specimen and 1800kN for 1.2m specimen. FE simulations agreed well with the observed failure modes and were used to investigate how the measured failure loads were influenced by grout material properties, cohesive bond behaviour and geometrical parameters such as shear keys and eccentricity. From the FE studies, it was found that different cohesive (surface) parameters are required to give the best fit, with the higher cohesive stiffness and strength associated with a higher failure load. Grout strength is also a significant parameter, but the effect of surface cohesion is less significant compared to material strength. The majority of the tested values were found to be meeting the minimum bond strength resulting from available standards (eg. ISO 19902). This type of real time testing output will provide insight into various parameters that contribute to bond strength in pile leg grouted connections. Moreover, these test and assessment results will form an integral and important input to various ongoing researches associated with ADNOC's grouted connections being carried out as part of another JIP led by National University of Singapore which is aimed at deriving design equations applicable to grouted connections beyond codal limits.
Expert Advisory System for Production Surveillance and Optimization Assisted by Artificial Intelligence
Authors: Mata Carlos , Saputelli Luigi , Mohan Richard , Rubio Erismar , Al Selaiti Iman , Badmaev Dorzhi
Published: December 2021

Petroleum Engineers are usually responsible for 50-200 wells. The wells in highly instrumented fields generate 10-20 measurements every few seconds. This makes it difficult to be on top of every well, every day. This challenge carries a significant opportunity cost, therefore the surveillance process requires automation by implementing surveillance-by-exception. Faster identification of problems is great, but not enough unless the required activities are executed in a timely manner. The ability to execute quickly and safely requires a well-structured coordination effort between the different disciplines involved in field operations.

In line with ADNOC Digital Transformation strategy, the solution described in this paper intends to couple surveillance by exception (a Petroleum Engineering workflow) with field operations execution (a multi-disciplinary set of workflows in the field). The integration is achieved by creating a simple yet robust action tracking system, and feeding it automatically with new opportunities, so that it is kept up to date. Automatic diagnosis becomes opportunities. Opportunities become activities. Activities are assigned, executed and closed. All activities are tracked on a high level, which provides insights and visibility to all parties on who is doing what, when and how to close the opportunity.

The surveillance by exception engine consumes real time measurements from the historian. It then runs a set of soft sensors using full physics, reduced order models, proxy and data driven machine learning models, which utilize most of the measurements. The measured and calculated values are then fed to an expert system, which automatically diagnoses the wells and creates tickets with recommendations to the production engineer. The engineer reviews the ticket and forwards to field operations for execution. The log of activities enables a direct measure of operational effectiveness.

This paper describes the philosophy of the system, how it works, lessons learned and the results of implementation across 6 oilfields and 600+ wells in Abu Dhabi.
Case History: Hydraulic Workover Unit Utilized to Recover Highly Corroded 30-Year Old Completion from a Live Gas Well in the United Arab Emirates
Authors: Avila Aurelio Marcano , Raji Abimbola , Ottolina Renny , Jimenez Jose
Published: December 2021

In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface.

This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered.

The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides.

This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section.

In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production.

The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.
Compressor Upgrade on Existing Platform: A Study on Vibration from Structural Perspective
Authors: Teh See Yee , A Rahman Ahmad Rizal , Raja Badrol Raja Sharifuddin Ahmad , Muhammad Daud Mohd Hafis
Published: December 2021

Due to an increase in gas lift demand on an existing field in Sarawak, an existing Gas Lift Compressor (GLC) on the processing platform requires to be upgraded to meet incremental oil production requirement. These sets of compressors consist of 2x100% reciprocating compressors that were designed for 1.5 MMscfd each, with discharge pressure of 55.1 barg (800psig). The gas from these compressors is used mainly for gas lift at the processing platform as well as gas lift, instrument gas and utility gas at adjacent wellhead platforms. From the Conceptual Study, the existing compressors are not able to be retrofit for upgrade and is to be replaced with 2 × 100 % new gas engine driven compressor that capable of delivery 3.0 MMscfd of compressed gas each.

During the engineering stage of GLC package, Skid Dynamic Analysis has been carried out to evaluate the GLC skid structural design due to the operating dynamic load cases. The study recommended that the skid to be welded to the platform where the compressor is located to prevent the risk of high vibration. With the recommendation from Contractor's study, project team proceeded to carry out Structural Dynamic Analysis to assess the dynamic effect of the GLC skids to the platform deck. The Finite Element Analysis (FEA) results revealed that there are several modal modes mainly at the drilling deck and extension deck non-compliance to PTS guideline. Structural Dynamic Modification (SDM) and optimization was performed to dynamically stiffens the structures to shift the modal modes away from the operating range to fulfil PTS criteria. However, the SDM results was still unable to comply thus the need of Anti-Vibration Mounts (AVMs) is considered. Prior to application of AVMs, Structural Forced Response Analysis needs to be carried out to evaluate the risk of the system and confirm the requirement of the AVMs. Without the forced response analysis, the effect of AVMs, locations and numbers of AVMs cannot be addressed during the design study.

This paper will discuss the issues concerning vibration from reciprocating compressors upgrade on an existing platform, changes in the existing operating and design philosophy, challenges in addressing compressor installation and utilization of AVM from the perspective of Project Team. The paper will also provide key lessons learn and recommendation for future considerations in Compressor upgrades on existing facilities from a Structural Engineering point of view.

The project is currently at its detail design finalization and installation is expected to be completed by November 2021.
Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions
Authors: Alfazazi Umar , Chacko Thomas Nithin , Al-Shalabi Emad W. , AlAmeri Waleed
Published: December 2021

Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties.

Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.
Underground Gas Storage Process Optimization Using Integrated Subsurface Characterization, Dynamic Modeling and Monitoring - A Case Study
Authors: Li Longxin , Zhou Yuan , Li Limin , Tinnin* John , Peng Xian , Cranfield Colin , Luo Yu , Guises Romain , Zhao Yuchao , Wang Xia , Gui Feng , Burns Christopher , Yu Huijuan , Younessi Sinaki Ahmad Reza
Published: December 2021

Underground gas storage (UGS) will be key to addressing supply and demand dynamics as natural gas consumption grows during the coming decades in response to cleaner energy initiatives. The XGS facility began UGS operations in a depleted gas field located in SW China in 2013. Following this initial period of utilization, the site was reassessed to safely increase deliverability during winter months to meet future peak gas demand.

The XGS field is located in a high tectonic stress region and has a structurally complex and highly faulted geological setting. The carbonate reservoir is heterogeneous and naturally fractured. Initial assessment steps involved determination of maximum storage capacity and estimation of required working gas and cushion gas volumes using fully integrated geological, geophysical, petrophysical frameworks. Geomechanical modeling was embedded into the analysis to determine the long-term impact inferred by cyclical variations of pressures on the reservoir performance and cap rock containment and evaluate both safe operating pressure limits and monitoring requirements.

The coupling of complex reservoir and geomechanical parameters was required to create a dynamic model within the stress regime that could be history-matched to the early gas depletion phase and subsequent gas storage cycles. Such a holistic approach allows the operator to optimize the number of wells, their placement, trajectories and completion designs to ensure safe and efficient operations and develop strategies for increasing withdrawal rates to meet anticipated future demand. Additionally, tight integration of subsurface understanding with surface requirements, such as turbo-compressors, is critical to meet the UGS designed performance and deliverability objectives and ensure sufficient flexibility to optimize the facility usage.

A further important task of the final phase of UGS facilities design involves enablement of sustainable operation through a Storage Optimization Plan. The results of the analyses serve as a basis for the design of this plan, in combination with fit-for-purpose surveillance systems of the reservoir and cap-rock seal recording pressure, rock deformation and seismicity in real time, along with regular wellbore inspection.
Unconventional Drilling and Creative Solutions Delivered World Record a Multi-Laterals Fishbone all Legs Drilled, Accessed and Stimulated First Attempt - Case Study from Kuwait
Authors: Farhi Nadir , Abdel Samie Mohamed Ahmed , Nouh Walid Saher , Ibrahim Hamdi Saber , Al-Ajmi Hadi Saad , Khan Youcef Mohammed , Merza Abdullah Jaffar , Hussain Talal Abdulhameed
Published: December 2021

Despite being the first area for oil to be found in Kuwait in mid 1930's, Bahra's oil production remained largely unexploited until 2015, when a major development campaign targeting one of its tight carbonate reservoirs through horizontal drilling and multi-stage frack completions was commissioned. Nonetheless, with the development and exploration initiatives underway, surface congestion is the primary challenge. As the number of wells increased the need for unconventional well profiles became more demanding. The multi-lateral fishbone approach was designed to have a total of four laterals with approximately 3000 ft each. Lessons learned from previous level-1 multi-laterals drilled in North Kuwait indicated that the primary challenge remained to be the ability to drill a smooth bore hole profile across the junctions to successfully re-access and stimulate all the drilled legs with coil-tubing to maximize production.

Kuwaiti Operator Reservoir and study team were looking for an alternate solution to increase the production in Bahra using multi-laterals technics in the same reservoir to stimulate and sustain production in calcite reservoir. Historically only three wells were drilled experimenting challenges and failures to open hole sidetrack leading to have long time to complete the wells with maximum 3 legs as record including the mother hole. RST team asked to drill a well with 4 legs, each leg following the same azimuth with the condition to be 300 ft apart. The thorough planning exercise completed and the close follow-up to the approved design of service during execution phase resulted in the successful delivery of the first four legs fishbone in Kuwait with Zero Non-Productive Time. In addition to achieving all the geological targets, the smooth borehole profile helped ensure successful re-entry and stimulation of all four legs in the same run achieving the well challenge using the unique
Case Studies of Digitalized Locate the Remaining Oil Workflows Powered by Hybrid Data & Physics Methods
Authors: Kuzmichev Dmitry , Moradi Babak , Mironenko Yulia , Hadian Negar , Lazar Raffik , Alessio Laurent , Rahmat Faeez
Published: December 2021

Mature fields already account for about 70% of the hydrocarbon liquids produced globally. Since the average recovery factor for oil fields is 30 to 35%, there is substantial quantities of remaining oil at stake. Conventional simulation-based development planning approaches are well established, but their implementation on large, complex mature oil fields remains challenging given their resource, time, and cost intensity. In addition, increased attention towards reduce carbon emissions makes the case for alternative, computationally-light techniques, as part of a global digitalisation drive, leveraging modern analytics and machine learning methods.

This work describes a modern digital workflow to identify and quantify by-passed oil targets. The workflow leverages an innovative hybrid physics-guided data-driven, which generates historical phase saturation maps, forecasts future fluid movements and locate infill opportunities. As deliverables, a fully probabilistic production forecast is obtained for each drilling location, as a function of the well type, its geometry, and position in the field. The new workflow can unlock remaining potential of mature fields in a shorter time-frame and generally very cost-effectively compared to the advanced dynamic reservoir modelling and history-match workflows.

Over the last 5 years, this workflow has been applied to more than 30 mature oil fields in Europe, Africa, the Middle East, Asia, Australia, and New Zealand. Three case studies’ examples and application environments of applied digital workflow are described in this paper. This study demonstrates that it is now possible to deliver digitalized locating the remaining oil projects, capturing the full uncertainty ranges, including leveraging complex multi-vintage spatial 4D datasets, providing reliable non-simulation physics-compliant data-driven production forecasts within weeks.
Assess Digital Maturity to Set Digital Transformation Strategy in Oil and Gas
Authors: Torre Mario , Azancot Analyn , Florez Fabián , Zhou Wei
Published: December 2021

This paper presents a structured methodology for an oil company to embark on a digital transformation. It was implemented in several JVs with a NOC that includes three producing blocks with dozens of mature fields.

The methodology has several key unique strengths: One is the ability to isolate the core-money-making processes and build a digital strategy around them. This shows early gains and at the same time becomes a buy-in support for management. Another advantage is the simplicity to define the "desired" digital maturity level using direct input from the final stakeholders. This is achieved by using the process enhancement method, a SIPOC technique (Supplier, Input, Process, Output, Customer analysis). Also, an important strength is the methodology does not ignore the existing IT infrastructure, nor the field systems (i.e., SCADA) and re-uses them, as much as possible, giving enough time for a transition or an upgrade when needed.

Several tools are provided in this paper that makes the methodology consistent, auditable, and strong to support the designed digital strategy to any management level with high chance of approval. The methodology is flexible enough to be run on various types of contracts, hydrocarbon phase or operational environments.

As with any method, it relies on commitment from the top and base line in the organization, requiring open and honest evaluation of current inefficiencies and, equally important, resources (budget and people).

In summary, a digital transformation is not a sudden leap from a company's current analog status to an instantaneous digital state of being. Rather, it is a progressive, step-by-step transition of core processes and user-centric workflows that requires careful planning and a thoughtful methodology to find the most suitable scenario for each company.
Fulfillment of Maintenance and Reliability Key Performance Indicators of Offshore Sites During Covid-19 Pandemic
Authors: Hussein Huda , Al Blooshi Shamsa , Saeed Waled , Al Salami Abdulla , Al Rais Masab , Herzallah Mohamed , Al Wahedi Mohamed
Published: December 2021

This paper addresses the challenging situation that was faced by Maintenance Teams in Offshore Sites to maintain and ensure the optimal conditions of the plants, conducting Routine Preventative Maintenance (RPM) as planned, achieving Company and Operational Excellence KPIs in the midst of COVID-19 pandemic. A brief description of how the sites defined a new normal given the circumstances to ensure all work was met while tackling the numerous obstacles in order to keep operations running smoothly is iterated below.