bluuebunny/crossref_metadata_2025 huggingface dataset:
Development and Qualification of a Unique ICD Completion Design to Improve Operational Well Efficiency
Authors: Arias Rommel E. , Al Mohanna Khalid S. , Guo Chengjun , Awid Abdurrezagh
Published: November 2020

Inflow control device (ICD) completions are becoming a crucial part for many green and brown field developments. However, a typical ICD completion requires a washpipe or inner string to provide fluid circulation, displacement and setting of openhole hydraulic-mechanical packers, which increases operational time, risks and costs.

A typical installation process has to follow a series of operational steps to ensure successful deployment of ICD completions. Those necessary operational steps are traditionally achieved using washpipe or an inner string that is run inside the lower completion bottomhole assembly (BHA). This unique and advanced ICD completion design uses proven sliding-sleeve technology that will be run in the closed position to provide fluid circulation, displacement and setting of openhole hydraulic -mechanical packers, and then hydraulically activated to the open position to allow for reservoir-to-well communication. It also incorporates a mechanical-shifting mechanism for future reservoir management and control.

The new and advanced ICD completion has undergone a rigorous testing program to ensure the design will deliver those operational requirements and perform appropriately under the worst well operational conditions that are expected during the field life. Following completion of the testing program, the advanced ICD completion was deployed flawlessly in a carbonate reservoir well in the Middle East, representing the first successful deployment globally. The system has functioned as expected with clear surface indication throughout the different operational steps and the final establishment of reservoir-to-well communication which was evidenced by the increase in the well head pressure (WHP). Furthermore, the individual ICD open or closed-sleeve status was verified through production logging (PLT) and coil tubing (CT) shifting operations.

The paper describes a comprehensive qualification testing program for the advanced ICD completion design to best serve those well-installation requirements without the need of washpipe. Furthermore, it details the actual well deployment which resulted in improved overall well completion design and operational efficiency.
Procedure to Complete, Running, Testing, Cementing, Hanging and Cleaning out the Frac String to Complete Unconventional HP/HT Wells to Guarantee the Future Frac Operations in the Wells Of Unconventional Project at Abu Dhabi UAE
Authors: Ruiz Fernando , Al Hadidy Khaled , El Yossef Bassem , Hebish Ayman , Negoi Adrian , Hamdy Ibrahim , Al Shamisi Eisa , Al Samahi Musabbeh , Kumar Rakesh , Mizukami Akio , Mandal Vivekananda , Ibrahim Ahmed , Wakka Turky , Al Soliman Abdulkareem , Nunez Ygnacio , Amorocho Alexander , Al Hendi Mohamed , Al Mutawa Ahmed
Published: November 2020

The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project.

In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations.

This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.
Prediction of Rock Mechanical Properties from Geochemical Signatures using Machine Learning Algorithm
Authors: Hussain Maaruf , Negara Ardiansyah , Amao Abduljamiu , Al-Ramadan Khalid
Published: November 2020

This paper presents a data-driven model built using machine learning technique, namely Support-Vector Regression (SVR), for predicting rock mechanical properties (RMP) of tight sands and shale formations based on measured elemental information. This study utilized 324 data points obtained from Paleozoic sequences covering 8000 ft interval. Elemental data was acquired by scanning intact samples on MicroXRF machine, whilewas used for modelling as well as for establishing lithofacies. RMP were obtained at atmospheric conditions using a non-destructive impulse hammer technique. SVR was used to establish a correlation between elemental geochemical information with RMP. The dataset was categorized into two: training and testing dataset using a 70-30 percent split. Training data was used to train SVR and establish the RMP prediction model by tuning the hyperparameters. Testing data was used to evaluate the predictive model by comparing the predictions with the actual measurement. Two quantitative measures for estimation accuracy including mean absolute error and cross-correlation plots between the actual and estimated RMP were employed to evaluate the prediction accuracy. The results demonstrate that the estimated RMP has a good agreement with the actual RMP, which is indicated by the small error and high coefficient of determination. Moreover, we used Adjacent Boosting technique to perform feature selections and the results show that the SVR-based model still generates good prediction when the number of features in the input is reduced by more than half. This study demonstrates that a reliable predictive model can be built with few intrisinc features, in the absence of robust mineralogical and elemental information.
Miscible Gas Injection EOR, Carbonate Reservoirs Well Injectivity Field Cases
Authors: Xu Siqing , A BinAmro Ahmed , Mabrook Maged
Published: November 2020

Miscible gas injection EOR is a well-established and proven recovery mechanism. There are a large number of miscible gas injection EOR developments worldwide. Some of these developments achieved relatively high recoveries. ADNOC is a leader in miscible gas injection EOR in carbonate reservoirs - with a number of developments within its portfolio contributing substantially towards ADNCO overall production.

For miscible gas injection EOR developments, especially in relatively low permeability carbonate reservoirs, the following are recognised as key field development planning and reservoir monitoring/management areas: Development pattern, number and location of injectors in relation to producersSufficient injection rate and volume, to maintain reservoir pressure and optimise sweepReservoir monitoring and production management, to ensure adequate data acquisition and studies to support field development and production decisions in a timely manner.

In relatively tight carbonate reservoirs, injection well injectivity is a critical factor when addressing the above three key areas. Water injection injectivity is fairly well understood, but gas injection injectivity in a miscible setting can be very complex. The complexity can be attributed to a combination of factors, for example: The dependence of injection gas property parameters on downhole injection pressure and temperatureDevelopment of the miscible oil bank via either vaporising or/and condensing mechanismVapour phase being significantly more mobile than reservoir liquid oil and waterWhere applicable, gravity segregation in areas surrounding the injectorReservoir wettability and hysteresis.

An assessment into miscible gas EOR injection injectivity for relatively low permeability carbonate reservoirs has been performed. Actual field injection data (both water injection phase and gas injection phase) from 3 reservoirs were analysed. A compositional sector model was also used. Injectivity evolution trends were discussed, and potential influencing factors identified. Recommendations on best practices for WAG injector injectivity monitoring, reservoir voidage replacement calculations are provided.
6 × 6 Occupational Health Hazard Risk Rating Matrix: A Useful Tool in the Determination of Risk Levels of Workplace Health Hazards
Authors: Ang Bufford , Kulkarni Poorva
Published: November 2020

The paper elaborates the utilization of a novel 6 × 6 Occupational Health Hazard Risk Rating matrix developed for oil and gas operations,enhancing the determination of occupational health hazards as comparedto a5 × 5 matrix in terms of clarity on severity and likelihood criteria. This paper describes how severity ratings were redefined, and how likelihood ratings were divided into qualitative and quantitative approaches.

To establish the severity rating definitions, health effect ratings were benchmarked from international industrial hygiene association guidelines, peer-reviewed literature, and hazard rating categories from oil and gas operations. The qualitative likelihood scheme was developed considering evaluation methodologies for various physical and ergonomic hazards, as well as formulation of control bands for biological and chemical hazards. The quantitative likelihood scheme was based on the concept of the 95% upper UCL of hazard exposure data and evaluating it against its OEL.

From the previous five (5) Severity of Harm categories (i.e., Minimal, Minor, Moderate, Major, Extreme), six (6) classifications were developed (i.e., Notable, Minor, Serious, Major, Catastrophic, Disastrous) specifying documented health effects posed by a workplace health hazard. From the previous five (5) Likelihood of Harm categories (i.e., Rare, Unlikely, Possible, Likely, Almost Certain), six (6) qualitative likelihood classifications were formulated (i.e., Very Low, Low, Medium/Moderate, Moderately High, High, Very High) considering current evaluation schemes for physical and ergonomic hazards and control banding for biological and chemical hazards. In addition, six (6) exposure bands were created by defining specific exposure rating categories based on an estimate of the 95% UCL relative to a health hazard’s OEL. Finally, the previous five (5) risk ratings (i.e., Extreme, High, Medium, Low, Negligible) were consolidated into four (4) risk levels (i.e., High, High-Medium, Medium and Low), with each level differentiated according to the control measures required and the exposure monitoring frequency requirement for the workplace health hazard.

The health hazard risk rating matrix is envisioned to make health hazard risk assessment process simple, more accurate, user-friendly, and consistent with international best practices for the following reasons: use of 95% UCL is the most appropriate metric to evaluate exposures on the upper tail of an exposure distribution as it acts as a reference point in assessing the exposure profile’s arithmetic mean with a health hazard’s OEL; new severity rating definitions mirror the actual health effects posed by a health hazard; and qualitative likelihood rating is reflective of globally accepted exposure assessment methodologies and control banding schemes.
A Novel Numerical Method to Model the Dynamic Underbalanced Perforation Process
Authors: Mohajeri Sina , Alizadeh Ali , Zeinali Mostafa , Rajabi Hamed , Madani Mohammad
Published: November 2020

The final goal in a perforation operation is achieving the maximum production and reducing perforation damage, using optimal completion process. The Dynamic Underbalanced Perforation (DUP) as one of the more recent completion technologies minimizes or even eliminates the perforation crushed zone by optimizing the well's dynamic underbalance. Dynamic underbalance is a transient underbalance process that occurs immediately after creation of the perforation tunnels. The modeling of this process is essential in designing the optimal configuration of the perforation charges to evaluate the perforation efficiency.

In this study we propose a novel and efficient numerical method, to optimize the completion efficiency which is rarely attended in the literature. There are five main steps in our modeling procedure: Calculating volume of the gas released in detonation,Calculating inner temperature of the Gun,Calculating remaining gas and energy amount inside the gun,Calculating pressure and casing stability analysis, and finallyCalculating perforation skin.

Although there are some computer programs that claim to model the DUP technology, none of them uses a fully numerical method. In fact, all of these programs use experimental data and correlations to predict the efficiency of this process.
Cdx- Upskilling Employees for Digital Transformation
Authors: Barreales David
Published: November 2020

The digital transformation is allowing through access to new technology (which years ago was not accessible to many companies) to address the traditional problems of their businesses with innovative and different approaches that are allowing them to be more efficient and sustainable. In many cases, it is also allowing them to face problems that years ago (without access to these technologies) had no possible solution.

Once we have all these new technologies available (Cloud Computing, Machine Learning, Big Data, etc) the main challenge that companies have is to equip themselves with the necessary skills to exploit these technologies to the fullest, that is, with people who are experts in the mastery of these technologies. All companies are trying to incorporate talent related to these disciplines and being these profiles very scarce (since many of the professions barely exist yet), this has led to a super inflation of the market for these professionals, making their recruitment very complex.

To the previous problem, we must add that technologies alone are not capable of transforming business models or achieve different approaches to traditional problems, professionals in technologies related to the digital transformation are experts in these technologies, but without a knowledge of business and the problems that have the different sectors are unable to add any value to business.

Therefore, in this paper we will explain how the best solution to address this problem is to train employees with a vast knowledge of traditional business in digital disciplines, through this solution you make the same professional converge traditional business knowledge with the opportunities offered by new technologies. This makes the approach to the problems is the right one, avoiding misalignments or cultural clashes between different teams and not having to go to a growing market to hire these professionals, the key to achieve this fit is to train from an experiential point of view that ensures the transfer of new knowledge to the workplace and the company can benefit from an innovative approach to traditional problems.
Using Fixed-Point Observation Experiments to Study the Expansion Law of Microfractures Induced by Shale Hydration
Authors: Tao Liang , Guo Jianchun , Li Geng , Chen Chi , Zhao Yuhang , Zhao Zhihong
Published: November 2020

Shale rocks are rich in organic minerals, also it contains multi-scale micro-nano pores, making flow mechanism of fracturing fluid in microscopic pores of shale and the interactions between fracturing fluid and shale very complicated. In this study, firstly, the initial microscopic pore structure of shale before hydration was analyzed by field emission electron microscope. Secondly, the dynamic changes of microscopic pore structure in shale hydration was observed at fixed points with the scanning electron microscopy to find out the correlation between induced micro-fractures and mineral components. Finally, the influence of hydration on the changes of shale physical properties was analyzed. The test results of shale sample from Longmaxi formation (LF) in the Sichuan Basin indicate the micro-fractures induced by shale hydration weremainly shale bedding fractures, with obvious directionality. Clay minerals play a leading role in the formation and expansion of induced fractures. After 10 days of hydration, the porosity can be increased by 2.1 times, and the permeability can be increased by 273.7 times. Therefore, an appropriate shut-in treatment can dramatically enhance post-fracturing performance. The research results can guide the optimization of flowback system and provide scientific basis for efficient development of shale gas reservoirs.
Digital Twin Implementation on Current Development Drilling, Benefits and Way Forward
Authors: Bimastianto Paulinus , Khambete Shreepad , AlSaadi Hamdan , Couzigou Erwan , Al-Marzouqi Adel , Chevallier Bertrand , Qadir Ahsan , Pausin Wiliem , Vallet Laurent
Published: November 2020

In the recurring need to optimize drilling operations and reduce costs, a full RTOC (Real Time Operations Center) solution was deployed as part of the organization structure. To bring accurate, automatic and relatable data capture from surface sensors, the RTOC introduced a digital twin approach to improve field to town collaboration. The paper will demonstrate the benefits brought to operations by the solution in terms of risk identification and lessons learnt.

RTOC digital twin solution integrates standard physical models’ workflows for hydraulics, torque and drag with advanced solutions using machine-learning algorithms. Capitalizing on operations recognition algorithm, the solution identifies thresholds and calibrates parameters to automatically classify operations into "Rig States" and "Drill States". The algorithm is trained to identify operational sequences and can derive complex measurements like downhole weight-on-bit and torque that are in turn fed into different workflows. This holistic event-based torque and drag baseline determination is used to define hole cleaning roadmap with minimum manual inputs.

RTOC receives, processes and publishes the real time data on through its platform for all drilling and completion operations. This continuous process has enabled drilling operations team to assess and intervene on a need basis thanks to the clear event identification it offers. Amongst the digital workflows, the hole cleaning roadmap, combines modelled and automatically identified torque and drag data points rendered and shared with the stakeholders to ensure the capture of deviations and framing of potential risks to acceptable levels through a common decision platform. The clear output of single identifiable drilling event (such as pick up, slack off and free rotating weight) provides constant fact-based data for an adequate protocol to run casings and liners and refine engineering designs. In turn it has enabled to break casing and liner run records in their different operating fields. The drilling efficiency roadmap rely on quantitative algorithm and reliable output of downhole weight-on-bit, downhole torque and mechanical specific energy with automatic calibration, without user intervention nor bottom-hole-assembly modelling, allowing to substitute actual downhole measurements. This has been a performance enhancer in the improvement of rate of penetration regardless of the availability of downhole sensors.

This new approach based on modern data science and digital twin based on a robust method, provides with a consistent and clear outcome regardless of service providers involved in the direct operations. It was trained, tested and validated prior to deployment, on more than 80 wells. This has also made possible the introduction of other algorithmic developments for Realtime dynamic modelling.
Automated Corrosion Mapping AI & Machine Learning
Authors: Majors Marc , Harrington Travis , Ferguson Eric , Dunne Toby , Potiris Steve , Vlaskine Vsevolod , Mohammed Jaffar , Bargoti Suchet , Naqshbandi Masood , Ahsan Nasir
Published: November 2020

Objective

Risk reduction and increased Fabric Maintenance efficiency using Artificial Intelligence and Machine Learning algorithms to analyze full-facility imagery for atmospheric corrosion detection and classification. Following imagery capture and processing, deficiencies are identified, and targeted mitigation strategies are executed at greatly reduced cycle time and cost.

Methods, Procedures, Process

A pre-mobilization facility scan plan is generated to maximize imagery quality, including high elevation scan positions, to ensure thorough and comprehensive analytics. Data from all scan positions are stitched together in a point cloud and aligned for accuracy relative to each location. Finalized imagery and point clouds are then tagged with unique piping line numbers per design, fixed equipment tags, or unique asset identification. The Machine Learning algorithm is intensely trained with manual ground truth inputs prior to analysis. The algorithm analyzes each pixel throughout the facility and detects, classifies, and reports on all identified corrosion, tagging faults to specific piping or equipment.

Results, Observations, Conclusions

Atmospheric corrosion is the number one Asset Integrity threat in the Gulf of Mexico. Utilizing this tool, we can have a comprehensive and objective analysis of a facility’s health in a matter of weeks from the time of data collection. Data collection for a large deep-water, spar facility requires approximately 12 days with 8 data scanning personnel. Conventional manual inspections incur higher risk, higher cost, and reporting is much less objective considering the number of inspectors involved and the duration of a full-facility campaign. Finally, all results are published in a user-friendly dashboard that can be filtered by process type, equipment type, corrosion severity, and many other criteria as the user requires. Each fault is associated with the specific equipment identification and the user can navigate to see the imagery of the corrosion in a 3D, photogrammetric environment. Remediation strategies can be collated into work packs for fabric maintenance teams, further Nondestructive Examination (NDE) assessment, or work orders for replacement. Fabric maintenance efficiencies are substantially realized by targeting decks, blocks, or areas with the highest aggregate surface areas of corrosion (on process equipment or structurally, as selected by the user) and concentrating remediation efforts on at-risk equipment.

Novel/Additive Information

This application of Artifical Intelligence and Machine Learning is a first-in-industry approach to having a comprehensive understanding of facility coating integrity and external corrosion threats. HSE analysis, Risk awareness, and targeted remediation strategies will make the Asset Integrity program more efficient, proactive, and reduce down-time across the Gulf of Mexico related to atmospheric corrosion.
A Novel Technique to Constrains kv/kh of Carbonate Reservoir, A Valuable Uncertain Parameters for History Match Process
Authors: Pamungkas Setiyo , Gueye Talla , Al Hammadi Fatema Yousef , Al Saadi Haleema Amer
Published: November 2020

A persistent challenge in reservoir modeling is to assign representative values for vertical permeability in reservoir models. It is a common practice to use kv/kh directly from the core measurements but this is not at the same scale as the model grid. It is also frequent to use one value for entire zones. The approach of using a single value applied to a single zone when the reservoir is heterogeneous is not correct and the same can be said regarding using core plug kv/kh as the grid scale is larger than the core plug therefore resulting in a difference in the statistical support of the two measurements.

This paper describes the technique to understand reservoir vertical connectivity by properly defining kv/kh, which later will be used as a matching parameter during the History Match process. Most of the time the data provided by the plugs is not appropriate due to the absence of vertical sampling or to problems of representativeness. Where plug data is available kv/kh ratios are often found to be close to one, a values too high to be realistic when considering the geological heterogeneity at small scale or plug scale. Even when plug measurements show homogenous at small scale (kv/kh ∼1), at grid cell scale the Kv and Kh are expected to be different (<<1). A methodology is proposed in order to give more appropriate ranges of values to the grid cell size, based on the small-scale permeability anisotrophy ratio (kv/kh) into grid cell size. A novel approach was established to get the ranges of kv/kh based on core mini-k measurements and core-plugs data.

This innovative workflow also considers a multi-disciplinary approach using Experimental Design methods to better understand and validate the kv/kh ranges. The main learning from this project is the importance of understanding vertical connectivity in a complex reservoir by properly capturing heterogeneity and other major geological features in the integrated 3D dynamic model with the aim to achieve an optimized history match at reservoir level but also more importantly on a well-by-well basis.
Gas Lift Well Operating Envelopes to Improve Production Operations: Field Applications in UAE
Authors: Mata Carlos , Saputelli Luigi , Mohan Richard , Rubio Erismar , Al-Attar Momamed Ali , Alhosani Abdulla , Al-Hosani Fatima , Reddicharla Nagaraju
Published: November 2020

Production operations in a modern oilfield production system becomes gradually more complex as the water cut increases and artificial lift is applied. To ensure production is continuously optimized, closer communication and a positive feedback loop are required between the petroleum engineer, the production supervisor and control room operators. ADNOC is developing a series of decision support systems to improve collaboration in production operations. One of the key systems consists of 2D operating envelopes charts for the gas lift wells, which relate the control variables of the wells, gas lift rate and production choke opening, with the expected flow behavior. The operating envelopes are visible in the control room and provide guidance to the operators on the stable production range of the wells, whilst leaving flexibility for adjustments, as the immediate production context evolves throughout the day.

The operating envelopes were computed by performing sensitivities on choke and gas lift settings on nodal analysis models of wells, chokes and flowlines, with different manifold pressures. The calculated rates and pressures are compared with a series of mechanical, reservoir and production constraints, to build the 2D envelope chart. The envelope shows the region where the well is in a stable and safe region, together with regions exceeding the maximum allowed casing pressure (MAWOP), hydrate formation, flowing below bubble point, exceeding allowed rates, tubing + flowline erosion, casing heading and tubing heading. The current operating point is shown in the chart, together with the recommended optimum setpoints.

Production operations use the system as a guidance tool to control the wells. The petroleum engineer is expected to keep the well models up to date, to make the operating envelopes robust. On the other hand, the operators are expected to test the wells frequently, to ensure the good quality of the models. Around 2-5% of oil production increase is expected from the continued use of this framework.
Advanced Combination of Proppant Fracturing and Sand Control Completion System Unlocks Gas Potential of Unconsolidated Jauf Formation in Bahrain
Authors: Prasad Vineet , Sultan Hussain , Al-Rumaidh Ahmed , Fateh Ahmed , AlTarif Nazar , Yudin Alexey , Md Noor Mohd Nazri , Fortuna Francisco , Guleryuzlu Metin , Al-Jalal Ziad
Published: November 2020

The Jauf formation of Bahrain's Awali brownfield is currently underdeveloped due to an extremely challenging geological environment. Because of high heterogeneity, the formation requires fracturing to produce economically. However, the Jauf sandstone is unconsolidated, and formation sand production does not allow for high gas rates. A combined solution was introduced using a completion assembly with frac ports and screens to restrict sand production with a tip screenout approach in the stimulation stage.

The studied well was completed with a 4 1/2-in. cemented liner that had been plugged and abandoned and left with 7 5/8-in. casing across the prolific Jauf sandstone. A completion string with screens and production sleeves, fracturing ports, and packers was deployed to compartmentalize and fracture the Jauf. Fracturing ports, while production sleeves were later manipulated with coiled tubing (CT) to allow production across the sleeve filter media, thereby preventing proppant or formation sand from being produced. A large fracturing treatment was placed in an aggressive tip-screenout mode to achieve optimum fracture length and maximize fracture conductivity. Afterwards, CT was used to close the fracturing port and open the screen ports to flow back the well and proceed with testing operations.

A hydraulically activated shifting tool was used to manipulate the fracturing ports (open and closed) as well as the production ports enabling gas production through the included screens. This technology enabled the fracturing operation to be executed in conjunction with sand management hardware during production, further providing more flexibility for future intervention operations when compared to frac-and-pack type assemblies. Considering the significant depth of the formation (11,700 ft), degradable fibers were used to minimize friction pressure and, respectively, maximize fracturing treatment rate to allow for optimum height coverage and lateral fracture penetration. The post-stimulation sand-free gas production rate through the screens was greater than 20 Mscf, which was confirmed with choke-variability testing operations conducted after manipulation of the completion ports. The trial well proved that proppant fracturing combined with innovative sand control hardware provides an effective method for producing gas from the prolific Jauf reservoir.

The described completion system represents an alternative to a traditional frac-and-pack hardware solution, enabling full control of the well with CT interventions. A tailored stimulation design and advanced placement technique coupled with detailed description of completion design and operations sequence will be of interest to experts dealing with tight unconsolidated formations in the Middle East and other regions.
Maximizing Liquid Recovery in Oil & Gas Processing
Authors: Karam Stéphanie , Valand Bhavesh N. , Aggarwal Rajdeep , Singh Harendra , Kamal Faris , Takieddine Oussama H.
Published: November 2020

Liquid Product Recovery is an important metric to assess the quality of Gas and Oil Separation plant design and is required to be achieved at minimum CAPEX & OPEX to improve the overall economics. This paper presents a structured approach for an optimal solution to minimize loss of valuable components to the gas phase, thereby maximizing liquid recovery.

Ideal Liquid Recovery is defined as the theoretical maximum liquid recovery possible by successively separating the lightest components from the well-fluid until the crude oil specifications are met, i.e. separating all the Methane (C1) and Ethane (C2), just the right proportion of Water, Propane (C3) and H2S to meet the specifications. In real life separation systems, however, such sharp separation is unachievable, i.e. some amount of intermediate and heavier components are likely to migrate to the gas phase and some of the lighter components may end up in the liquid phase. Accordingly, %Liquid Recovery is defined as: %Liquid Recovery=Actual Liquid RecoveryIdeal Liquid Recovery×100

Oil and gas production is a complex process wherein many equipment and systems are closely coupled and interdependent. The art of designing an optimal process for Gas and Oil Separation plants lies in rigorous selection of appropriate process configurations and operating conditions. The design largely depends on several factors such as fluid compositions and properties, product specifications, etc. There is no single configuration or set of process conditions that can be the solution under all scenarios; thus each case requires to be analyzed independently.

This paper uses a structured approach to evaluate the impact of each parameter individually as well as collectively, to select the optimum process configuration for separation and stabilization of the crude oil. A Gas and Oil Separation plant with multiple stages and a stabilizer column is used to demonstrate that the liquid recovery for a specific well-fluid composition can be maximized by varying separator operating conditions, column operating parameters and process configurations. The focus of the paper is on the ‘Design Process’ to achieve and assure an optimal design as well as understand its limitations.

The suggested design approach demonstrates that liquid recovery values in excess of 95% can be achieved in comparison to typical liquid recovery values of around 93% for low GOR oil production plants. Even two percent increase in liquid recovery is quite significant, as on a 100,000 STBOPD plant it translates to 2,000 STBOPD production gain which is equivalent to more than US$ 33 million per year in additional revenue at crude oil price of US$ 50/bbl. This should be read with a caveat that incremental absolute revenue will be lower in a smaller capacity unit and hence, additional CAPEX, if any, should be evaluated accordingly. Higher liquid recovery also contributes to improvement in API gravity of the crude, and thus further adds to its value.
Utilization of the Innovative A.S.C. Technology for 24/7 Solar Enhanced Oil Recovery
Authors: Al-Maaitah Ayman
Published: November 2020

The objective of this paper is to demonstrate the usage of the innovative ASC technology on low cost storage of solar thermal energy to generate high pressure steam for 24 hours a day and 7 days a week to be utilized in Enhanced Oil Recovery (EOR). The technology is patented, simulated and tested at Masdar Solar Platform in Masdar City- Abu Dhabi. Simulation showed that the solar radiation is concentrated by thousands of times allowing for high temperature hot air receive fixed to the ground. The heated air will then be used to store thermal energy in low cost compact bed refractory materials or even bedrocks. Thermal energy can be retrieved upon demand and high-pressure steam can be generated to be utilized in Solar Enhanced Oil Recovery. The concentration of solar energy at a fixed focal point allows easy storage and utilization of solar energy. Temperatures at around a Thousand Degrees Celsius were obtained even at low solar radiation which allows energy to be stored in low cost compact bed and high-pressure steam can easily be generated even during night. Financial and technical feasibility of the system is being investigated. The system is self-cleaning and has low wind resistance hence not needed to be placed inside a glass house. The temperature and energy of the hot air is measured in various weather conditions and is simulated to be stored in a compact bed refractory ceramic materials. The size of the system is scalable and modular hence it can meet the demand for any scale. The novelty of this technology is of its low cost and ability to store solar energy cheaply to supply it upon demand.
Stimulation of Oil and Gas Wells in Carbonate Formation by Using Supercharged Nanoparticles
Authors: Sergeev Vitaly , Tanimoto Kenji , Abe Masashi
Published: November 2020

An article presents results of comparative analysis for evaluation of effectiveness of classical stimulation technique and innovative technique applied in the same mature carbonate oil-gas formation within two years. An innovative technique is based on a two-stages treatment of bottom-hole zone of production well with chemical compositions characterized by different impact onto the oil and gas bearing formation: water-blocking agent; water solution of acid-surfactant composition. An application of a new water-blocking agent – emulsion system with supercharged nanoparticles (ESN) as a first step of well treatment solves two following tasks: diversion of acid composition and long-term blockage of water bearing most permeable intervals of the formation thickness. The ESN is characterized by unique physicochemical properties such as high thermal stability, stability under filtration in porous media, enlarged surface activity, self-regulated rheology and reversibility of blocking effect. A combination of these properties in one solution makes positive impact on an efficiency of stimulation technique resulting in a redistribution of permeability profile within reservoir thickness and moderation of water-cut under increased fluid rate. A classical stimulation technique considered in this article is a one-stage treatment of production well by water solution of hydrochloric acid. Mature carbonate formation of Abdulovskoe oil-gas field considered in this study is found in Ural-Volga oil and gas province, Russia. The Abdulovskoe oil-gas field is under industrial development since 1970, and to date remained recoverable reserves are highly deteriorated. Moreover, the formation rocks are characterized by relatively high net sand coefficient (0.26), low porosity (0.10) and low matrix permeability (0.02 μm2). The net of natural fractures caused noticeable wells interference between the producer-producer as well as injector-producer, which complicates the oil-gas formation development process.
Addressing the Current Practice of Over Estimation of Structural Resistance of Existing Strengthned Structure.
Authors: Sharma Madhugiri Shashi , Patel Pareshkumar , Omar Tarek , Sarkar Anjan , Atia Mohamed
Published: November 2020

Present regional practices for performing a conventional offshore structural analysis erroneously considers strengthening proposed for any additional loads on existing structures to also support the already existing loads which mainly is due to the limitations of the linear analysis approach presently adopted. This method could lead to false perception of code compliance exposing strengthened structures to a higher failure risk. The paper introduces a more accurate approach for the assessment of the structure and the evaluation of the effectiveness of strengthening introduced at different stages through the structure’s lifetime.

Through the course of this study, a comparison was carried out between the conventional linear strength analysis vis-a-vis the non-linear finite element analysis technique for a typical offsore structural Bridge. The work involved full simulation of a bridge supported by two offshore structures using the conventional method and assessing the results. Subsequently an integrated finite element model, with critical locations represented through 4-node shell elements was generated. A non-linear finite element analysis was adopted where stage-wise strengthening and load history was simulated.

The structural assessment using the non-linear finite element analysis technique has demonstrated that the bridge did not comply with the structural strength requirements of ISO 19902 international standards in as-is condition. This was in contradiction to the conclusion and outcome of the previous design reports. The previous strengthening design had adopted the conventional linear design methods, ignoring the realistic effects of loading and strengthening stages throughout the history of the structure. Ignoring these effects had misled to the perception of effectiveness of the new combined sections, whereas accurate representation had demonstrated that only the new additional loading is distributed to the new combined section and the existing loading is resisted by original sections only. This behavior is applicable if the installation techniques did not include jacking systems to relieve the loading prior to strengthening.

The results and conclusions of the study have given an insight to the limitation of the conventional linear structural analysis methods in capturing the accurate structural behavior. It also provided a demonstration of how an incompatible type of assessment may lead to incorrect perception of compliance.
Interpretation of Mini-Frac and Flowback Pressure Response: Application to Unconventional Reservoirs in the UAE
Authors: Alhashmi Omar , Eker Ilkay , Kazemi Hossein
Published: November 2020

The main objective of the research presented in this paper was to develop a working knowledge of the unconventional shale in the UAE Diyab formation which includes reservoir engineering evaluation of the UAE Diyab Upper Jurassic gas condensate and Shilaif Middle Cretaceous light oil shale development. To achieve this objective, (1) we measured core permeability of a couple of Diyab cores with and without fractures, (2) we analyzed the pressure fall-off data from a Diagnostic Fracture Injection Test (DFIT) to determine in-situ matrix permeability for use in reservoir evaluation, modeling, and forecasting reservoir performance, and (3) we determined the effective permeability (that is, combined permeability of matrix and microfractures) of a Diyab stimulated well using rate transient analysis (RTA). Furthermore, we put together both analytical and numerical models for single-phase and two-phase flows in support of the interpretation of the field pressure falloff DFIT data, and the data from a laboratory DFIT conducted in a granite core by Frash in 2014 to shed light on enhanced geothermal reservoirs. Finally, we calculated the depths of filtrate invasion and the cooled region surrounding the hydraulic fracture surfaces to determine the net stress change near the surface of hydraulic fractures, which is commonly referred to as the ‘stress shadow' effect.

We concluded that our research effort was both informative and instructive in determining the effectiveness of the stimulation efforts for the wells used in this study, and the process can be similarly utilized in any shale stimulation effort elsewhere.
Recent Advances in Waterless Fracturing Fluids: A Review
Authors: Almubarak Majed , Almubarak Tariq , Ng Jun Hong , Hernandez Julio , Nasr-El-Din Hisham
Published: November 2020

Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing.

Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant.

The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO2, energized, and foamed fluids (CO2 and N2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable.

This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.
Sour Gas Has A Sweeter Future - Bulk H2S Removal Using Polymeric Cellulose Triacetate Based Membranes
Authors: Sanghani Pinkesh , Kumar Hans , Ghorbani Nasser , Morisato Atsushi , Mahley George
Published: November 2020

Approximately 40% of current global natural gas resources have high H2S and CO2 concentrations. The H2S concentration in Middle East gas reservoirs can potentially reach up to 30 mol%. H2S is toxic; therefore, the produced natural gas must be treated and sweetened. In this high H2S environment, a membrane technology that can remove the bulk of H2S from produced natural gas will reduce the load on the amine treatment and sulfur recovery unit operations downstream in gas processing facilities. Bulk removal of acid gases with membrane technology will lower SO2 emissions through a reduction in flaring, elemental sulfur production from sulfur recovery units, and reduce unit delivery costs for the life of the field.

Since 1984, Schlumberger has deployed cellulose triacetate polymeric membranes for CO2 removal in gas processing and EOR applications. In collaboration with a major oil and gas exploration and production company, our membrane science research team is testing cellulose tri-acetate acid gas removal membranes to characterize separation performance under a variety of process conditions. The team deployed a pilot system capable of testing gas with 25% H2S in the USA. These membranes will separate both acid gas components, CO2, and H2S from the feed gas and retain hydrocarbons in the residue gas sent to the amine system for further processing. Low-pressure acid gas permeate can be reinjected into the reservoir for enhanced oil recovery or sequestration.

Initial laboratory testing and predictive modeling of the membranes, completed with an American academic research institution, have shown promising results for bulk H2S removal. Pilot system testing data will further de-risk and validate the feasibility of technology deployment and facilitate economic modeling of this technology's business impact. We will present the results of the testing to date which will form the basis of the observations and conclusions of the paper.

This paper will also present a case study to show the business impact of deploying a hybrid system (membranes + amine) in comparison to a conventional amine system.

After testing, operators will have satisfactory information available to review alternative processing facility concepts and re-evaluate the economics of ultra-sour gas field development projects.