bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated 1-D and 3-D Basin Modelling to Characterize the Deposition and Distribution of Asphaltenes Within Tar Zones from an Oil Field Offshore Abu Dhabi, UAE and Qatar
Authors: Holloway Daniel , Kelly Ranald , Kay Daniel , Gill Claire , Ishibashi Masatoshi , Al-Hitmi Ruqaya Hassan Ali
Published: December 2021

Increasing the recoverable reserves from oil fields by extracting from tar zones is becoming more desirable in the Middle East. One approach for improved definition of tar zones is to understand the factors which affected the deposition and distribution of asphaltenes within the target interval. In this paper we outline how integrated 1-D and 3-D basin modelling was used to identify the timing of hydrocarbon generation and expulsion from the Jurassic source rock to charge a prolific Jurassic carbonate reservoir formation of an oil field, offshore Abu Dhabi, UAE and Qatar.

The source rock is modelled to be in the peak oil mature window today, with the onset of oil generation from the Cenomanian to the Turonian, depending on modelled and assumed source rock kinetics. The onset of oil expulsion was from the earliest Paleocene. Measured bulk fluid parameters in the reservoir formation have a significantly higher Gas-Oil Ratio (GOR) and elevated API gravity values when compared with predicted values. A possible mechanism to explain this discrepancy would be to invoke the contribution of higher GOR fluids from more mature source rocks within the fetch area of the field.

Thermochemical sulphate reduction of anhydrite layers in the reservoir is predicted to have begun during the Eocene. Major uplift and erosion in the Oligocene and Mio-Pliocene significantly reduced reservoir pressure and temperature. This reduction in pressure and temperature is modelled to have caused precipitation of solids, gravity segregation and flocculation at the then oil-water contact, depositing the main tar zone and patchy tar in the reservoir beneath this zone as charge continued through time.

We present a detailed review, interpretation and 3-D basin model; the first study of its kind conducted on this oil field. The 3-D basin model predicts the timing of the deposition and distribution of asphaltenes in the carbonate reservoirs of the studied field and demonstrate that local problems need to be understood in their regional context.
Several Decades of Fluid Diversion Evolution, Is There a Good Solution?
Authors: Casero Alberto , Gomaa Ahmed M.
Published: December 2021

The success of any matrix treatment depends upon the complete coverage of all zones. Consequently, the selection of the diversion technology is critical for treatment success. While various types of diverting agents are commercially available, the proper selection of optimal diverter depends on many factors, including well completion and history, compatibility with reservoir and treatment fluids, treatment objectives, operational constraints, and safety and environment considerations.

The study will cover five major types of non-mechanical diversion technologies considered as potential solutions for offshore deepwater oil reservoirs: dynamic diversion, relative permeability modifiers (RPM), viscoelastic surfactants (VES), particulate diversion, and perforation diversion. All of them, but a dynamic diversion, are based on different chemicals or products to be added to the injected treatment fluid, and occasionally some can be complementary to each other.

Given the offshore and deepwater settings, mechanical diversion techniques were not covered in the study, aiming to find a solution that would achieve acceptable diversion while minimizing operational effort, which would enable riser-less intervention and the use of light intervention techniques.

This study was driven by the need to effectively stimulate a 500ft of a cased and perforated interval with a permeability of 500 md, and injection rate limited to 16 bpm due to completion limitations. The sandstone formation, with static in situ temperature of 270F, was far beyond the applicability of dynamic diversion and, to achieve the desired full coverage for the planned scale inhibition treatment required and combination with another diverter system was needed.

The process applied included compatibility tests, regained permeability tests, and test well trials. Depending on the specific diversion product analyzed the testing procedures were adapted to obtain the information to properly guide to the optimal solution.
Untapping the Full Potential of Long Length Tubular Grouted Connections to Ensure Sustainability of Offshore Structures
Authors: Abdelkhalek Ahmed , Atia Mohamed , Sarkar Anjan , Keys Matt , Patel Mahesh , Eissa Mohammed , Omar Tarek , Choo Yoo Sang
Published: December 2021

Questionable pile-jacket grouted connections’ reliability posed threat to the sustainability of 200 wellhead platforms with ages up to 60 years and averaging at 45 years. Industry standards fell short in guiding fitness for service assessments for these connections that fall outside the applicability limits of their formulae. This paper presents key findings from the laboratory testing supported study, which demonstrated the platforms’ long-term FFS and led to multi-billion Dollars savings.
Comparison of Z-Factor Correlations Using a Large PVT Dataset with Emphasis on the GERG-2008 EOS
Authors: Mogensen Kristian , Merrill Robert
Published: December 2021

The gas compressibility factor is an important property in reservoir simulation studies. It is directly linked to the gas formation volume factor and the gas density thereby impacting wellhead injection pressure, reservoir voidage, injectivity, as well as the tendency for gas gravity override to occur in the reservoir.

ADNOC's PVT database contains experiments on almost 2,000 samples, of which more than 100 have been subject to advanced gas injection experiments. Z-factor data have been compiled from the liberated gas during DV experiments as well as from CCE experiments on reservoir gases, injection gases, and swollen fluid mixtures. Several of these mixtures are very rich in H2S, whereas pressure and temperature are in the range of 14.7-14,500 psia and 80-365 °F, respectively.

We test several different methods for predicting the Z-factor, such as the industry-standard Hall-Yarborough method, in combination with various models for pseudo-critical pressure and temperature and including correction for non-hydrocarbon components. Other methods tested include the GERG-2008 model, considered to be state-of-the-art for predicting physical properties for well-described gas mixtures, as well as the well-known Peng-Robinson cubic equation of state.

Based on close to 10,000 data points in our database, the GERG-2008 model typically predicts the Z-factor to be within 2% of the measured value, which is on par with the experimental uncertainty. However, for some rich gas condensate mixtures, the model gives larger errors because its parameters are only tuned to compositions with components up to C10. This is to our knowledge the first time that the GERG-2008 EOS has been compared to standard Z-factor correlations for such a large number of data points.

If compositional information is available, we recommend using either the GERG-2008 model or the Hall-Yarborough model with pseudo-critical properties provided by Kay (1936). When compositions are not available, we find that the Standing correlation is more accurate than the Sutton model, also for sour mixtures.
A Comparative Evaluation of Thermodynamic Models for Prediction of Wax Deposition
Authors: Ismailova Jamilyam , Abdukarimov Aibek , Mombekov Bagdat , Delikesheva Dinara , Zerpa Luis E. , Dairov Zhasulan
Published: December 2021

Wax deposition on inner surfaces of pipelines is a costly problem for the petroleum industry. This flow assurance problem is of particular interest during the production and transportation of waxy oils in cold environments. An understanding of known mechanisms and available thermodynamic models will be useful for the management and planning of mitigation strategies for wax deposition. This paper presents a critical review of wax prediction models used for estimation of wax deposition based on chemical hydrocarbon compositions and thermobaric condition. The comparative analysis is applied to highlight the effective mechanisms guiding the wax deposition, and how this knowledge can be used to model and provide solutions to reducing wax deposition issues. One group of thermodynamic models assume that the precipitated wax is a solid solution. These models are divided into two categories: ideal (Erickson and Pedersen models) and non-ideal solutions (Won and Coutinho models). In the other group of models, the wax phase consists of many solid phases (Lira-Galeana model).

The authors summarized the limitations of the models, evaluated, and identified ways to represent the overview of existing thermodynamical models for predicting wax precipitation.

Within the strong demand from industry, the results of this manuscript can aid to aspire engineers and researcher.
Challenges and Mitigation in Achieving Successful Project Handover
Authors: Esro Murnisa , Yahaya Mohd Hafizd , Ahmad Nur Shairah
Published: December 2021

This paper will describe the common challenges faced by both Project Management Team (PMT) and Asset Owner when projects come to the tail end and due for handover. It highlights the impact of improper handover of projects to the company as a whole and provides some proposals to address the common project handover issues. This paper will cover mainly on project handovers for upstream projects especially related to offshore facilities. This paper is written based on sample of projects done at offshore Malaysia. It highlights the common handover issues such as PMT not able to handover timely to the Asset Owner although the facilities are running, and production had been achieved. The longer it takes to handover, the more monetary value leakage will be wasted as a result of no equipment preventive maintenance, warranty of equipment could expire or void, and paying higher construction insurance coverage. This can be prevented by a proper and early planning in managing handover, inclusion of segmented provisional acceptance criteria in the contract as well as having frequent engagement between PMT and Asset Owner prior to stages of handover during project execution. Understanding of each stakeholders' expectations is also one of the key success factors. This paper will conclude that there are many common handover issues when it comes to project handover. Most of the issues are the results of misunderstanding of each stakeholder's expectation, poor early handover planning and unclear scope of acceptance in the contract. In most cases the impact will lead to unrealized monetary value leakage. Early handover planning, clear scope covered in the contract, good coordination between PMT and Asset Owner, good teamwork and mindset, blending with some interpersonal skills in managing conflicts are among the key success factors. The key highlights in this paper will help PMT and Asset Owner in better managing the project handover. This will improve project delivery to meet target schedule within scope and budget. This will eventually safeguard overall company investment and avoid any risk on uncertainty of care and custody transfer at the end of a project life cycle.
Unlocking Opportunities for Gas Lift Well Surveillance - Building the Framework for Consolidated Data Capture and Processing
Authors: Cornwall Rachelle Christine , Shkorin Daniel Dima , Guzman Rodrigo Alberto , El-Majzoub Jalal Rojdi , El-Sedawy Mahrous Sadek , Pribadi Giftan Febrian , Deng Yunhui , Alhur Mohammed Abdulrahman
Published: December 2021

Gas lift operations are highly dependent on data quality and team competence to operate the asset efficiently. Traditional methods for gas lift well surveillance and diagnostics rely on wireline services, a method with growing constraints to adapt to constantly evolving well and operational challenges. The Well Intervention-less Tracer Surveillance System (WITSS) provides a cost effective, comprehensive approach to well surveillance without the reliance on tools entering the well. This results in reduced HSE risks and no associated deferred production.

This paper describes a pilot implementation to evaluate the adequacy and accuracy of this technology in the context of ADNOC Onshore gas lift producers. The objective is to evaluate its performance against conventional method data sets and assess the reproducibility of data where no reference existed. The 10 well pilot included both accessible and obstructed wells. Data from the custom designed modular portable kit used for executing the surveillance activities, was analyzed and compared against conventional flowing gradient surveys with full data consumption in well models for comprehensive nodal analysis and opportunity identification.

For this pilot, ten wells were surveyed twice using the WITSS method. Results were compared to traditional methods acquired through wireline surveys for accessible wells, and against established multi-phase flow correlations for obstructed wells. The pilot confirmed the WITSS method is as accurate as conventional gauge measurements in mapping pressure and temperature profiles in gas lifted wells.

The WITSS method provided additional insight on accurate gas consumption based on the assessment of total gas lift utilization per well and allowed comprehensive model calibration and well performance definition. It also identified potential integrity issues via identification of primary injection at designed stations and secondary unwanted injection sites. Continuous compositional gas analysis of both injected and produced gas streams provided additional verification for analyzing gas lift injection performance. It also highlighted a change in fluid compositional analysis opening discussions for material selection review of the assets.

Production uplift identified from 50% of wells was compliant with the reservoir management strategy. The value proposals of flow stabilization through gas lift valve re-calibrations and replacements, adjustment of injection flow rate and further controls on injection pressure management are under process for implementation. Full field scale up scenario is under preparation.
Application of Full Waveform Inversion to Time-Lapse Walkaway Vertical Seismic Profile Data for CO2-EOR Monitoring in Abu Dhabi: A Feasibility Study on Field and Synthetic Data
Authors: Mouri Takuji , Shigematsu Aijiro , Nakamura Yuki , Kato Ayato , Ichikawa Masaru , Kitawaki Yuta , Sakata Genki , Ishiyama Tomohide
Published: December 2021

This study aims to investigate the feasibility of CO2-EOR monitoring by full waveform inversion (FWI) of time-lapse VSP data in an onshore CO2-EOR site in Abu Dhabi. CO2-EOR monitoring using conventional time-lapse surface seismic in onshore oil fields in Abu Dhabi is often technically challenging for two main reasons. The first is that elastic property change in response to pore fluid substitution is relatively small because the elastic modulus of the reservoir rock frame is far larger than that of the pore fluids. The second is the low repeatability of time-lapse survey data due to high amplitude surface-related noise which varies temporally. However, seismic monitoring with FWI of time-lapse borehole seismic data may offer a solution for these issues. FWI is capable of detecting small velocity changes such as those associated with pore fluid substitution. Furthermore, borehole seismic surveys may provide more highly repeatable, higher quality data compared to surface seismic surveys because borehole seismic data is less affected by surface-related noise. This study consists of two parts, a field data analysis and a synthetic study. In the field data analysis, we studied the resolution and repeatability of FWI results at field-data quality, including the presence of actual noise using time-lapse VSP data. VSP data was acquired at the very early stage of EOR and there was no CO2 injection in the time between the two time-lapse VSP surveys. As a result, a high-resolution P-wave velocity model, consistent with a sonic log, was obtained. The P-wave velocity model also revealed excellent repeatability between the two survey data sets. In the synthetic study, time-lapse FWI was performed using synthetic VSP data representing pre- and post- CO2 injection periods. The results of the synthetic study showed that even in the presence of realistic 4D noise, which was estimated in the field data analysis, FWI successfully delineated the distribution of velocity changes caused by CO2 injection when the cross-sectional area of the injection-induced velocity changes were larger than the resolution of the FWI results. With these results, we demonstrated that FWI using time-lapse VSP data was applicable for CO2-EOR monitoring in the field as long as the criteria were met. This conclusion encourages the application of FWI using time-lapse VSP data for CO2-EOR monitoring in onshore Abu Dhabi.
Using Risk Based Maintenance Optimization RBMO to Save Costs
Authors: Mohamed Khaled Ahmed Farouk
Published: December 2021

Maintenance is a crucial pillar in plant integrity and availability. Saving money in maintenance should be established without affecting the asset's integrity. Based on this, the core of work is to maximize the maintenance return on investment (ROI). Maintenance ROI is the ratio between invested money in maintenance to mitigated risks due to maintenance actions. The objective is to minimize maintenance cost while maximizing assets integrity and availability.

RBMO starts with ‘Maintenance Criticality Assessment’ (MCA) at unit/system level to define high (20 % of systems that represent 80% of risks), medium (20% of systems that represent 15% of risks), and low critical systems (60% of systems that represent only 5% of risks). Based on system criticality, a dedicated risk assessment is implemented to evaluate risks at tag level to define the worst maintenance action/s.

High critical systems’ maintenance programs are developed using ‘Reliability-Centered Maintenance’ (RCM). Medium critical system maintenance program is developed using ‘Failure Mode, Effects and criticality analysis’ (FMECA). "Maintenance strategy for Low Critical item" guideline document is developed to define the best maintenance strategy for low critical units.

All risks are evaluated using the standard ADNOC risk matrix. The risk is converted to monetary value in $ to evaluate maintenance actions using a formula.

A special program was developed to facilitate MCA evaluation for each system and represent risk as monetary value using ADNOC Risk Matrix taking into consideration the redundancy and demand on a system during operation. MCAs were completed for all ADNOC Onshore Assets, see results below. Optimization starts by evaluating maintenance programs for low critical systems to save costs where low critical systems represent 50% to 60% of total systems in ADNOC Onshore. Based on this the total number of work orders has decreased by 6856, which is equivalent to saving $1M annually.

In parallel, RCMs are conducted on high critical systems. Risk mitigation calculator in $ value was developed and embedded in the RCM information sheet to calculate cost benefit from implementing maintenance programs that were developed.

RBMO is a systematic and traceable methodology to minimize maintenance cost and at the same time maximize system integrity and availability.

This work showed the importance of reviewing the low critical systems’ maintenance program, as a first step in RBMO after implementing MCA, where low critical systems represent 50% to 60% of total assets and only 5% of total risks. ADNOC Onshore developed a dedicated guideline document "Maintenance Strategy for Low Critical Item" to facilitate decision making for proper maintenance strategy for low critical systems. Adding RCM risk mitigation calculator to RCM to calculate RCM cost benefit.
Offshore Structure Specific Performance Targets
Authors: Atia Mohamed , Abdelkhalek Ahmed , Sarkar Anjan , Keys Matt , Patel Mahesh , Eissa Mohamed , Omar Tarek
Published: December 2021

Offshore structures exist in the harshest environments and each region is unique in the severity and development of extreme weathers. This had led to challenges in the identification of a single criterion that's internationally applicable. ADNOC Offshore and Kent, formerly Atkins Oil and Gas, worked closely in 2010 to develop a high-level generalised regional criterion for the Arabian Gulf and in 2020, a major project was conducted to develop a structure-specific criterion that resulted in considerable improvement in risk levels and financial gains.

For each of ADNOC Offshore's 480 structures, a Response Based Metocean Analysis (RBMA) was conducted adopting Tromans and Vanderschuren (1995) approach. Structure specific hindcast data at 3-hour intervals over a period of 37 years was analysed, isolating storms and executing hydrodynamic analyses considering joint environmental conditions. Through adopting a combination of peak-over-threshold method and Markov-Chain-Monte-Carlo (MCMC) simulations, convolution of long-term (storms) and short-term (wave probabilities within a storm) was conducted resulting in the generation of the Hazard Curves that account for the possible uncertainties associated with variations in each of the distributions.

The structure specific response based metocean analysis resulted in a considerable improvement in the criteria for ADNOC Offshore’s structures. The resulting Hazard Curve ratios (10,000-year to 100-year response parameter ratio) for approximately 95% of the structures were evaluated lower as compared to the 2010 generalised study. It was observed that the water current profiles had a significant impact on the hazard ratios, and specially for assets in the vicinity of the islands. Based on the resulting hazard ratios a detailed risk assessment was conducted and compliance and life extension of most of ADNOC Offshore structures was justified without the need for physical strengthening of their assets.

Through the use of machine-learning algorithms associated with serval statistical sampling techniques, extreme value analysis was conducted in conjunction with the MCMC approach and resulted in what is likely to be the largest offshore fleet application of the method.
Bulk Rheology and Injectivity Assessments of Potential Biopolymer and Synthetic Polymer for Applications in Carbonates Under Harsh Conditions
Authors: Elhossary Deena A. , Sebastian Anoo , Alameri Waleed , Al-Shalabi Emad W.
Published: December 2021

Polymer flooding is a well-established chemical EOR technology that is used to overcome challenges associated with conventional waterflooding including viscous fingering and early breakthrough. Nevertheless, polymers tend to perform poorly under harsh reservoir conditions of high temperature and high salinity (HTHS). The main objective of this study is to evaluate and compare the performance of two potential polymers, an ATBS-based polymer and a biopolymer (Scleroglucan), in carbonates under harsh reservoir conditions. This comparative study includes an analysis of polymer rheological experiments as well as polymer injectivity tests. The effects of water salinity and temperature on the performance of these two polymers was also investigated in this study. Rheological experiments were carried out on polymer samples at both ambient (25 °C) and high temperature conditions (90 °C). Polymer viscosity was measured as function of concentration, temperature, and salinity at different shear rates ranging from 1 to 1000 s−1. Injectivity characteristics of both polymers were also assessed through coreflooding experiments using high permeability carbonate outcrops at room (25 °C) and high (90 °C) temperature conditions. The injectivity tests included two stages of brine pre-flush and polymer injection, which allowed assessing the resistance factor (RF) of these polymers. These tests were conducted using high salinity formation water (167,114 ppm TDS) at both temperature conditions.

The bulk rheological tests showed that both ATBS-based and Scleroglucan polymers exhibit a shear-thinning behavior. However, the shear-thinning effect is far more evident at higher concentrations in the case of Scleroglucan as opposed to that of the ATBS-based polymer. Viscosity measurements of the polymer samples at different salinities demonstrated the detrimental impact of salinity and divalent ions on the stability of ATBS-based whereas Scleroglucan was not much affected. Scleroglucan exhibited better filterability at the high temperature as opposed to the room temperature. From the injectivity tests, the shear-thinning behavior of the biopolymer in the porous media was confirmed as RF decreased with increasing the flow rate applied at both temperature conditions. Meanwhile, the ATBS-based polymer exhibited a shear-thickening behavior at 25 °C, but a shear-thinning one at 90 °C. Compared to the biopolymer, the ATBS-based polymer showed better injectivity at both the room and the high temperatures as the differential pressure stabilized within the first few pore volumes injected. This study highlights the importance of polymer screening for EOR applications in carbonate reservoirs under HTHS conditions.
A Study of Seepage Characteristics of Unsteady Waterflooding Development for Fractured Ultra-Low-Permeability Reservoir
Authors: Liu Qing , Li Xiangfang , Yang Jian , Feng Sen , He Minxia , Fang Yongjun
Published: December 2021

Unconventional fractured ultra-low-permeability reservoirs play an important role in continental sedimentary basins in China, and their formation characteristics and seepage laws are greatly different from that of traditional reservoirs. In this paper, the influence of microfractures and unsteady waterflooding on the productivity of fractured ultra-low permeability reservoirs are studied deeply. The reservoir parameters used in the study are from an actual fractured ultra-low-permeability reservoir in Ordos Basin, where microfractures are developed but macroscopic fractures are not. The microfractures have a small opening and are widely distributed in the reservoir, so the reservoir numerical simulation model adopts the equivalent continuous matrix model to simulate waterflooding. On one hand, the physical model of micro-fractured reservoir and the permeability tensor model of the equivalent continuous matrix are established. The results show that the existence of microfractures can increase the permeability of matrix by 1.4 times. On the other hand, an ideal heterogeneous numerical simulation model composed of pure matrix and equivalent continuous matrix considering microfracture is established according to actual geological parameters of the fractured ultra-low-permeability reservoir. To simulate and compare the unsteady waterflooding and continuous waterflooding development in 10-year development under the condition of constant annual injection rate, the results indicate that unsteady waterflooding development make higher productivity and lower water cut and lower formation water saturation than that of continuous waterflooding. By conducting unsteady waterflooding development simulation for sensitivity analysis, the results demonstrate that the greater the capillary force, the better the role of capillary imbibition in a certain range, meanwhile, the unsteady waterflooding has the best exploitation effect when the value of water injection cycle time is 100 days and the fluctuation amplitude of water injection rate is 1. At the above situation, the displacement and capillary imbibition and pressure disturbance achieve the desired effect of reducing water cut and increasing oil production.
Improving Long-Term Hydraulic Fracture Conductivity in Carbonate Formations by Substitution of Harder Minerals
Authors: Samarkin Yevgeniy , Aljawad Murtada Saleh , Amao Abduljamiu Olalekan , Sølling Theis Ivan , Al-Ramadan Khalid , AlTammar Murtadha J. , Alruwaili Khalid M.
Published: December 2021

Hydraulic fracturing is applied in tight formations to create conductive paths within the reservoir. However, the conductivity of the created fractures declines with time due to the closure stresses. The decline is sharp in soft formations because of proppant embedment and fracture surface asperities failure. The improvement in fracture surface hardness can mitigate the abovementioned challenges and sustain the fracture conductivity. This research targeted enhancing carbonate rock's hardness by forming minerals harder than calcite.

Carbonate rocks, namely dolomite, limestone, and chalk, were treated at ambient temperature conditions by immersion into the aqueous solutions of NaF and ZnSO4 with a concentration of 0.1M. During treatment, the solution was sampled to monitor the changes in ion concentration and estimate the reaction kinetics by ICP - OES and IC devices. The hardness of rock samples was measured by impulse hammering technique before and after the treatment. The changes in rock's mineralogy and elemental content were studied by XRD and SEM imaging. The permeability of rocks was estimated by the steady-state gas injection method.

The formation of smithsonite (ZnCO3, Mohs scale hardness - 4.5) and fluorite (CaF2, Mohs scale hardness - 4) was achieved in the reaction of calcite (CaCO3, Mohs scale hardness – 3) with ZnSO4 and NaF, respectively. Chalk and limestone reacted efficiently with both solutions; however, the dolomite reaction with solutions was feeble. XRD detected the newly formed smithsonite minerals, and it was observed in SEM images that minerals formed an interconnected net in chalk and limestone specimens. In dolomite samples, the minerals formed isolated gatherings that were sparsely located on the grains. The treatments caused the improvement of the rock specimen's hardness. 0.1M solution of NaF was not effective in strengthening the rock samples (only chalk sample experienced 6.7% improvement in hardness) because of low concentration of the solutions used; however, treatment resulted in negligible changes in permeability of the samples. In contrast, Young's modulus of limestone and chalk treated by ZnSO4 increased by 17% and 21%. Permeability of rocks treated by ZnSO4 reduced drastically, most likely due to the formation of gypsum as a byproduct of the reaction.

This research presents a method for carbonate rock hardening via the transformation of parent calcite into harder minerals. It explains its possible application in the petroleum industry to sustain the conductivity of propped/acid fractures. The proposed technique will help to mitigate fracture conductivity decline due to proppant embedment and asperities failure issues that are especially severe in soft formations.
The World's First Offshore GASWAG EOR Full Field Implementation
Authors: Khanifar Ahmad , Bin Subari Ibrahim , Bin Abd Raub Mohd Razib , Deo Tewari Raj , Bin Sedaralit Mohd Faizal
Published: December 2021

A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method.

This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper.

This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly.

The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.
Inventory Verification in Underground Gas Storage Rebuilt from Depleted Gas Reservoir: A Case Study from China
Authors: Song Lina , Xu Hongcheng , Wanyan Qiqi , Liao Wei , Zhang Shijie , Shi Lei , Zhao Kai
Published: December 2021

Inventory verification is one of vital tasks in underground gas storage (UGS) management process. For one reason, it is possible to know exactly how much natural gas is actually in the gas storage and ensure that it can be produced and supplied to the market in winter season when needed. For another, possible natural gas leakage can be discovered in time by inventory verification, to ensure the safe and economic operation of the gas storage. HTB UGS is a gas storage facility rebuilt from a depleted gas reservoir in China, which has been commissioning in June 2013. After 7 years injection-withdrawal cycles, we calculated and analyzed the inventory of this gas storage.

First and foremost, we analyzed the data of 13 observation wells, including monitoring of gas-water interface, caprocks, and faults of the HTB UGS. In addition, we carried out core experiments in the laboratory to simulate the multi-cycle injection and withdrawal of gas storage, and analyzed the microscopic pore seepage characteristics of the reservoir during the UGS operation. Next, based on the operating pressure test data of the gas storage, we corrected the formation pressure and calculated the effective inventory. Furthermore, combined with the simulation results that we have carried out in the previous period, the effective inventory of HTB UGS was comprehensively evaluated.

The result shows that: 1) The complete monitoring system indicates that the HTB UGS has no gas escaping from the storage field through faults, caprocks or wellbore. 2) The experimental result shows that in the process of gas withdrawal, various forms of natural gas such as jams and bypasses in some areas of the reservoir cannot participate in the flow, leading to this part of natural gas cannot be used. 3) Inventory calculation shows that as of the end of gas withdrawal in March 2020, the book inventory of HTB UGS is 99.8×108m3，while the effective inventory is 91.8×108m3 and the working gas is 39.9×108m3. 4) By acidification or other measures to improve the geological conditions, intensifying the well pattern and extending the gas production time, HTB UGS can increase its effective inventory.

With the great efforts in constructing underground gas storage in China and the market-oriented operation of UGS, inventory verification of gas storage will become increasingly important. The inventory analysis method established in this article can provide a certain reference.
IR 4.0 Technologies Enable Breakthroughs in Upstream Production Operations
Authors: Al-Hajri Nasser M. , Ureiga Sulaiman T. , Barghouti Akram R. , Gilani Syed K. , Javed Muhammad Imran
Published: December 2021

The fourth industrial revolution (IR 4.0) has brought about many exciting and game changing technological advancements in recent years that span across different industries. Our petroleum industry was no exception. In this paper, we will present realizations of IR 4.0's fruitful impact on multiple upstream production engineering and operation problems.

The first IR 4.0 technology uses machine learning techniques to predict scale inhibition and design inhibition programs that arrest scale formation. Scale formation is a common oilfield problem that consumes a lot of expense from operators. The machine learning method has shown its ability to curtail such expenses and manage risks associated with scale formation. The second technology is modeling the reliability of downhole Inflow Control Valves (ICVs) and predicting their failure. The technology is based on advanced big data analytics and uses automated statistical techniques to achieve the method objectives. This technology provides production engineers with an analytical decision-making model to predict ICVs failures and suggest the optimum frequency for stroking or cycling of the downhole valves as a preventive maintenance practice. The third IR 4.0 technology is the automated well integrity risk ranking. This particular technology uses smart interfaces and advanced computation algorithms applied on big data to assign (or weigh) risks of a well in terms of well integrity. This intelligent integrity ranking or classification shifts focus to wells prone to integrity failures more than the healthy ones. In addition, the method helps optimize integrity surveillance resources and prevents the obvious setbacks from a well integrity issue.

The paper will explain detailed methodologies of all three IR 4.0 technologies and outline expected results from field implementation of those technologies.
Automation of Carbonate Rock Thin Section Description Using Cognitive Image Recognition
Authors: Shebl Hesham Talaat , Al Tamimi Mohamed Ali , Boyd Douglas Alexander , Nehaid Hani Abdulla
Published: December 2021

Simulation Engineers and Geomodelers rely on reservoir rock geological descriptions to help identify baffles, barriers and pathways to fluid flow critical to accurate reservoir performance predictions. Part of the reservoir modelling process involves Petrographers laboriously describing rock thin sections to interpret the depositional environment and diagenetic processes controlling rock quality, which along with pressure differences, controls fluid movement and influences ultimate oil recovery. Supervised Machine Learning and a rock fabric labelled data set was used to train a neural net to recognize Modified Durham classification reservoir rock thin section images and their individual components (fossils and pore types) plus predict rock quality. The image recognition program's accuracy was tested on an unseen thin section image database.
Improved Simulation Efficiency for Optimising Inflow Control Device Completions Using Suitably Upscaled Models and Parallel Global Search Optimisation Techniques
Authors: Awid Abdurrezagh , Guo Chengjun , Geiger Sebastian
Published: December 2021

Inflow Control Device (ICD) completions can improve well performance by adjusting the inflow profile along the well and reducing the influx of unwanted fluids. The ultimate aim of using ICD completions is to provide maximum oil recovery and/or Net Present Value (NPV) over the life of the field. Proactive ICD optimisation studies use complex reservoir models and high-dimensional nonlinear objective functions to find the optimum ICD configurations over the life of the field. These complex models are generated from fine scale detailed geological models to accurately capture fluid flow behaviour in the reservoir. Although these high-resolution geological models can provide better performance predictions, their simulation runtimes can be computationally expensive and time consuming for performing proactive ICD optimisation studies that often require thousands of simulation runs.

We propose a new workflow where we use upscaled and locally refined models coupled with parallelised global search optimisation techniques to improve the simulation efficiency when performing ICD optimisation and decision-making studies. Our approach preserves the flow behaviour in the reservoir and maintains the interaction between the reservoir and the well in the near wellbore region. Moreover, when coupled with parallel optimisation techniques, the simulation time is significantly reduced.

We present an in-house code that couples global search optimisation algorithms (Genetic Algorithm and Surrogate Algorithm) with a commercial reservoir simulator to drive the ICD configurations. We evaluate the NPV as the objective function to determine the optimum ICD configurations. We apply and benchmark our approach to two different reservoir models to compare and analyse its efficiency and the optimisation results.

Our analysis shows that our proposed approach reduces the run time by more than 80% when using the upscaled models and the parallel optimisation techniques. These results were based on a standard dual-core parallel desktop configuration. Additional results also showed further reduction in run time is possible when employing more processors. Additionally, when testing different ICD completion strategies (ICDs in producers only, ICDs in injectors only, and ICDs in both producers and injectors), the NPV can be increased by 9.6% for the optimised ICD completions.

The novelty of our work is rooted in the much-improved simulation efficiency and better performance predictions that supports ICD optimisation and decision-making studies during field development planning to maximize profit and minimize risk over the life of the field.
Depositional Processes of the Cenomanian-Turonian Reworked Carbonates in the Eastern Abu Dhabi, UAE
Authors: Shimomura Takahiro , Yamanaka Motoyoshi
Published: December 2021

There are a limited number of studies and exploration cases for a "reworked carbonate" in Abu Dhabi, although these sediments are composed from some large oil and gas fields around the world (e.g. Poza Rica oil field in Mexico and Ruby gas field in Indonesia). In this study, we focused on Cenomanian-Turonian carbonates and considered the depositional processes of a "reworked carbonate" in the eastern part of Abu Dhabi.

To understand the stacking pattern and/or depositional process of the Cenomanian-Turonian carbonate, we conducted a well-well correlation for total 16 wells, based on the core observations, wireline logs correlation (GR, Neutron, Density, Resistivity and Sonic), carbon and oxygen isotope analysis and trace elements analysis. Sampling was conducted for 8 wells and samples were taken approximately every 5 ft. In addition, to predict the spatiotemporal expansion of the reworked deposit, a 3D seismic interpretation was conducted.

The result of the well-well correlation reveals that the depositional process and the stacking pattern of the Cenomanian-Turonian shoals around eastern Abu Dhabi are well consistent with the depositional model that proposed by Razin et al., 2010, and the reworked deposits are developed around the distal environment. 3D seismic interpretation represents that these reworked sediments were input from the north-west side and spread to the south-east like as a submarine-fan. Considering the core observation result, cohesive debris flow deposits are dominated at the depositional up-dip side and dilute flow deposits are dominated in the depositional down-dip side. In addition, an obvious erosional surface can be recognized in seismic sections and it truncates the top shoal sediments. The result of both, a combination of localized up-rift and global eustatic sea level fall in the early-middle Turonian triggered the regional erosion which is recognized as the middle Turonian unconformity. The result of this study suggests that the shoal sediments were eroded and reworked to a more distal environment at the early-middle Turonian.
Boronic Ester-Polyurethane as a Self-Healing Coating Material for Offshore Top Side Structures Application
Authors: Samsudin Mohd Shamsul Farid , Aba Norfarah Diana , Zakaria Muzdalifah , Nor Azmi Mohammed , Varley Russell , Zhang Jane
Published: December 2021

Polymer coatings, especially epoxy and polyurethane paint systems, have been widely used to prevent corrosion of metallic components and structures. However, due to environmental and mechanical effects, the barrier efficiency of the coatings may be substantially compromised during transportation and service, as demonstrated by localized scratches, delamination, or stress-related microcracks. Application of a self-healing coating that can restore damages and recover its performance with minimal external intervention could prevent corrosion at the damaged coating. In this present work, the healing efficiency and long-term durability of Boronic Ester (BE) blended with Polyurethane (PU) as a self-healing system for top side coating of offshore platform structures was investigated. The BE was mixed at a ratio of 50:50 with PU resin and applied as a top layer on a PU coated steel plate with a thickness of approximately 300-350 μm. The healing efficiency, mechanical performance, and durability under simulated environmental conditions such as salt spray and UV were investigated according to the related ASTM standards. As a first step, the electrical impedance spectroscopy (EIS) and 3D profilemeter microscope were used to assess the healing ability of the scratched coating at room temperature and humidity level of 85 %. The mechanical performance of the self-healing coating layer was evaluated using a pull off adhesion test to investigate the compatibility of the self-healing system with the existing commercial PU topcoat system, while a long term 3000 hours salt spray and 4200 hours cyclic UV test were performed to evaluate the self-healing coating's durability in harsh conditions. Preliminary assessment using EIS and 3D profilemeter microscopes on the scratched PU/BE self-healing coating revealed significant healing efficiency of more than 80% for healing condition at ambient temperature and humidity level of 85%. The self-healing coating layer also demonstrated excellent adhesion efficiency, with adhesion greater than 300 psi suggesting good compatibility of the BE-PU layer with commercial PU coating. The salt spray and cyclic UV tests that were performed to determine the durability of the self-healing coating revealed that the 50BE/50PU layer remained intact and exhibited good healing performance with more than 80% efficiency even after exposure to harsh conditions. The findings from the study demonstrated that the BE/PU material has the potential to be used as a self-healing system for topside coating of offshore platforms structures, thereby lowering maintenance costs.