bluuebunny/crossref_metadata_2025 huggingface dataset:
Not All Unconventional Reservoirs Are Similar: MENA Regional vs. Global Anisotropic Rock Index and Mechanical Characterization – Part 1
Authors: Gramajo Eduardo , Rached Rached
Published: February 2022

Unconventional formations require advanced mechanical and index assessments to improve their understanding under different geomechanical processes. However, difficulties associated with obtaining cores from the target formations and the challenges with sample preparation increase the assessment complexity.

This research compiles data from unconventional index properties and rock mechanical test results from published articles and reports. The parameters include rock mineralogy, rock mechanical properties (compressive strength and elastic properties), and petrophysical properties (porosity, TOC, and permeability). The study showcases the main differences between the global and regional (Middle East and North Africa) rock formations and presents the best analogs for the regional reservoirs. These findings supplement the scarce and complex procurement of the needed rock specimens and reduce the number of core samples required for detailed evaluations. These outcomes help reduce the costs (equipment, sample preparation, measurement time, and the number of specimens tested) associated with the unconventional rock experimental evaluation. In addition, this study explores the successful development strategy implemented in the unconventional reservoirs in China to accomplish commercial production and recommends appropriate rock analogs for detailed experimental evaluations.

This paper is part of an in-depth literature data compilation of MENA regional and global unconventional formations. This section of the study focuses on the target unconventional formations of Saudi Arabia and the unconventional formations in China, the USA, and Canada.
Modeling Frac Hits: Mechanisms for Damage Versus Uplift
Authors: Fowler Garrett , Ratcliff Dave , McClure Mark
Published: February 2022

Parent/child interactions pose a critical challenge for oil and gas shale producers (Roussel et al., 2013; Yaich et al., 2014; Rimedio et al., 2015; Miller et al., 2016; King et al., 2017; Dhuldhoya and Dusterhoft, 2017; Cipolla et al., 2018; Whitfield et al., 2018; Rainbolt and Esco, 2018; Lindsay et al., 2018; Gale et al., 2018; Scherz et al., 2019; Guo et al., 2019; Jin and Zoback, 2019; Kumar et al., 2020; Zheng et al., 2020; Gupta et al., 2020). The industry has progressed significantly in its understanding of causes and mitigation. However, important uncertainties remain. Fracture driven interactions or more commonly, "frac hits", exhibit varied behaviors in different basins. In the majority of basins, parent wells exhibit production loses after a frac hit. We examine and contrast a case study in the Bakken where production uplift occurs to observations of production loss in a STACK case study in Oklahoma. We show the productivity enhancement in the Bakken case study is driven by proppant transport and fracture conductivity amplification, with no apparent skin or conductivity damage. This suggests that absent specific damage mechanisms, frac hits alone can improve productivity via repressurization and increased propped area. In the STACK case study, fracture conductivity damage reactions must be introduced in order to match the historical data. This suggests that in the STACK, and perhaps other basins, additional processes are occurring in the subsurface to hinder the productivity of wells after frac hits. We postulate that minerology, petrophysics, and reservoir condition differences between basins causes differences in impacts of the fracture driven interactions.
Optimization of NMR Permeability Transform and Application to a Source Rock Reservoir
Authors: Chen Jin-Hong , Althaus Stacey , Boudjatit Mohammed
Published: February 2022

Permeability is a fundamentally important property of reservoir rocks that governs the flow of the reservoir fluids and production rates. Many methods have been developed to estimate permeability, including well established and documented laboratory measurements on whole core and plugs, analysis of formation test data, and analysis of production. Obtaining permeability from nuclear magnetic resonance (NMR) T1 or T2 has proven to be a cost effective method that can provide continuous permeability along a wellbore. This method uses a transform function on NMR well log data to calculate permeability. An accurate NMR permeability transform requires calibration to fit local data of a specific field based on measured data from representative cores from the field. The general form of the permeability transform developed for conventional sandstone and carbonate reservoirs does not work well for extremely tight reservoirs such as source rocks. Here we show a generic optimization method to find the optimal permeability transform for any tight reservoirs using NMR log data and laboratory measured permeability data from samples at selected depth of the logged well. This optimization method is applied to a source rock well and a permeability transform was obtained. The transform is a function of the movable fluid in the rock and logarithm mean of the NMR relaxation time. The permeability calculated from the transform is comparable to measured permeability from core samples.
Combining Hydrajetting Perforations and Hydraulic Fracturing Services – Value Added and Lessons Learnt from Operations in CBM Wells in India
Authors: Mirani Ankit , Tripathi Soniya , Srivastav Ashish , Chandak Raj
Published: February 2022

Coal Bed Methane (CBM) development in India has emerged as one of the cleanest solutions to the fuel energy requirements of this energy-starved country. Favorable market scenarios and lucrative gas prices are enabling operators in this business to target aggressive well-completion schedules. This study discusses the techno-economic benefits realized by the operator company of using combined coiled tubing (CT) deployed hydrajetting and fracturing services instead of conventional wireline perforations in CBM wells.

The service company introduced a unique fracturing service that integrates six processes – depth correlation with CT, hydra-jet perforation, hydra-jet fracture initiation, hydraulic fracture stimulation, zonal isolation using a sand plug, and wellbore cleanout using CT. It completes these processes in one single trip-in-hole, making the service cost and time efficient and eliminating the use of wireline for perforating and setting bridge plugs in the well which requires multi-stage fracturing. The technology in use, lessons learned, and knowledge gained from operations in India are shared in this paper.

The process employs a customized CT bottom-hole assembly (BHA) at the core of its service. Customized engineering solutions for hydrajetting can be developed based on casing specifications, cementing conditions, and stimulation design. The principle of hydrajetting perforations and the BHA details are discussed along with its benefits over the alternative techniques. The experience gained during operations allowed the service company to optimize jetting flow rates, differential pressures, and back pressures to improve its operational efficiency and also allow maximum proppant to be placed into the formation being stimulated. Implementing the lessons learned increased the hydrajetting tool life from 25-30 sets of perforation to about 40 per tool. The paper also discusses job design improvements implemented to prevent sanding up the wellbore leading to stuck CT. Finally, the paper discusses the economic benefits achieved by the operator company leading to increased productive time and a faster rate of well completion.

CBM fields require excessive dewatering before they break out gas and become commercially viable projects. The technology discussed in this paper enables the operators to put the maximum number of wells on production, in a shorter period maximizing the Net Present Value (NPV) of the asset.
GHG Emission Reduction at First Saudi Aramco CC&I Project
Authors: Ahmari Sultan , Mufti Abdullatef
Published: February 2022

The paper objective is to demonstrate the successful operation & maintainability of Carbon Capturing & Injection (CC&I) Project. CC&I project is one of the major Saudi Aramco projects to reduce Greahhouse Gaseous (GHG) emissions as one of the company key environmental aspects. The project is located in the Eastern Province of the Kingdom of Saudi Arabia at Hawyiah NGL Recovery Plant (HNGLP).

The project started capturing the CO2 in 2015 from HNGLP Acid Gas Removal Units (AGRUs) and then inject nearly 750 Kton per year of carbon dioxide into oil wells for sequestration and enhanced oil recovery maintainability. In most of gas plants, acid gas (primarily CO2 and H2S) is treated till achieving certain air quality parameters before thermal oxidizing process. After CC&I project, acid gas (only CO2 for HNGLP) is captured inlieu of thermal oxidizing. CC&I project has several processes from CO2 capturing to injection as follows: integrally geared multistage compressor, standalone dehydration system using Tri-Ethylene Glycol (TEG), CO2 recovery system, Granulated Activated Carbon (GAC) to treat water generated from compression and dehydration systems for reuse purpose, and special dense phase pump that transfers dehydrated CO2 at supercritical phase through 85 km pipeline to one of South Ghawar Field Wells to replace typical oil recovery enhancement technique (sea water injection). CC&I project is unique as it has several new technologies and experiences represented by the compressor capacity, pumping supercritical fluid at very high pressures, using mechanical ejector application to maximize carbon recovery, and using TEG as dehydration medium with CO2. CC&I project design considered the noise hazards generated from the compressor operation via installing engineering enclosure with proper ventilation system.(1)

This project helped HNGLP to minimize the total GHG emissions from combustion sources by nearly 30-35% comparing with before. It also helped to reduce nearly 75-80% of the consumed fuel gas to run the thermal oxidizers in AGRUs and send it as product as sales gas. The project helped to increase HNGLP business sustainability performance measures (less energy consumption by 8-9% and nearly 5-6% water reserves sustainability).
Assessing Sustainability Strategies in the Oil and Gas Sector through the Sustainable Development Goals. A Case Study of a Multi-Stakeholder Innovation Ecosystem
Authors: Menéndez Jaime , Fernández Jorge , Araujo Andrés
Published: February 2022

Developing effective sustainability strategies by oil and gas (O&G) companies requires that they embrace the global call to incorporate the United Nations’ Sustainable Development Goals (SDGs) into their business strategies and operations. However, more attention is needed in the academic literature regarding the analysis of the linkage between O&G companies and the SDGs. A previous study by the authors proposed an analysis process in order to assess sustainability strategies in the O&G sector, based on the combination of two sources of information provided by relevant international organizations in the energy field. This initial research focused on a small number of SDGs, which may not reflect the complexity of the approach to sustainability by an O&G company. Therefore, an extension of the analysis is introduced in this paper following a research with two stages. The first stage is based on case study methodology (taking a refinery in the Basque Country, in Northern Spain). This yields a qualitative identification of different avenues that the O&G company under study can follow to contribute to targeted SDGs with its own technological and industrial resources and current research and innovation projects. Building on this, the second stage of this line of research focuses on identifying which business relationships are the result of the activities and projects that contribute to SDGs. As a whole, the universe of business and non-business relationships constitute a growing multi-stakeholder innovation ecosystem on which the company relies to achieve its sustainability objectives. This innovation network around the refinery's operations encompasses a variety of stakeholders (companies, technology and research centers, universities and others) working on innovative projects related to hydrogen and synthetic fuels production, circular economy, electric vehicles, energy storage, renewable energy communities or digitalization, among other technologies and energy carriers. This ecosystem is supported by a web of public-private cooperation schemes at different government levels. The outcome of this approach to innovation reflects how, by adopting a multi-energy strategy, the analyzed company can act as a catalyst for innovation spillovers and synergies in the whole Basque Country region, which has implications that go beyond energy and climate issues.
Novel Internal Coating System for High Concentration H2S Environments
Authors: Lauer Robert
Published: February 2022

Traditional internal coating systems relied on phenolic, novolac, epoxy or blended resin systems. These tended to provide good barrier properties in the environments they were developed for, but as with all materials, there were limitations. One of those limitations that had to be overcome during the development and application process was that during the curing process, they can tend to shrink, so greater surface preparation processes must be followed to ensure that the system adhesion far outweighs the residual stress in the coating system. In sweet applications, this residual stress offers little to no effect on a properly applied coating system provided its design parameters are not exceeded. In the presence of higher concentrations of hydrogen sulfide, there can be a negative effect on the adhesion of most of these resin type coating systems allowing the residual stress to play a role in blistering and disbondment. A new and novel resin system has been developed that does not shrink during the curing process and can be applied as a primer-less system. Coatings developed with this new resin, benzoxazine, allows the coating system to maintain good adhesion and barrier properties in H2S concentrations two to three times greater than the current leading H2S resistant coating systems on the market today. This paper is the second in a series on the development of this product into a coating solution. Further laboratory refinement will be discussed leading to the next phase of the roll-out which will be field trials.
Evaluation of Biot's Coefficient Using Sonic Logs and Elastic Moduli Minimization
Authors: Vorobiev Sergey , Vorobyev Vladimir , Lukin Sergey , Zhigulskiy Svetlana , Chebyshev Igor
Published: February 2022

Biot's coefficient is one of the key parameters in estimating effective stresses, leading to understanding of the three stresses spatial distribution, namely vertical, minimum and maximum horizontal. Ultimately, these stresses shape up the behavior of a geomechanics model (either in 3D or in 1D). Thus, the robustness of any geomechanics model significantly depends on the precision of Biot's coefficient estimation. The proposed technique allows evaluating isotropic and anisotropic Biot's coefficients based on the log responses independent of the geological environment.

The methodology is based on elastic moduli-minimization. In isotropic case, Bulk rock frame and Bulk rock grain moduli minimization produce the best fit to the measured Density, DTP and DTS. Then, isotropic Biot's coefficient can be computed directly. In the case of anisotropy, additional control on lamination is required. This can be achieved by comparing estimated laminated and dispersed clay volumes based on the anisotropic rock-physics model and derived from the Thomas-Stieber plot or any alternative lamination analysis technique. Anisotropy modeling allows to produce five independent VTI elastic moduli and as a result to compute anisotropic Biot's coefficient.

The methodology has been tested in several fields: clastic (Western Siberia, Norwegian offshore, Argentina unconventional) and carbonates (Brazil, Middle East, North Sea chalks). It produces reliable results in all cases. This study shows good agreement of the Biot's coefficient computed from the proposed methodology with measurements of core-based Biot's coefficients. In practice, core-based Biot's coefficient measurements are rarely available and quite often done on a few samples, taken in the reservoir section only. The proposed methodology allows reliable estimates of Biot's coefficient for the entire wellbore section, where density and sonic logs are available. It utilizes a minimization technique instead of using geomechanics correlations. Thus, it is applicable for any rocks and geological settings and is not bounded to the area or formation compared to correlations specific to the particular formation.

The novelty of the method is in the process of elastic-moduli minimization based on logs and allows direct extraction of the Biot's coefficient. Previous works were either concentrating on principles of the laboratory Biot's coefficient measurements or focusing on the correlations derived from core tests. Correlation derivation requires a significant number of core tests conducted for the same geological settings. However, the proposed methodology requires a few core samples for Q.C. purposes only.
Pressure Transient Analysis in Shale Wells with Heterogeneous Fractures by Using a Deep Learning Based Surrogate Model
Authors: Chen Zhiming , Dong Peng , Wang Tianyi , Cai Mingjin , Tian Yong , Zhang Jiali
Published: February 2022

With hydraulic fracturing technology, manmade fractures can be generated around the shale-gas wells. After hydraulic fracturing at each stage, many wells in shale reservoirs have the "shut-in" process, which providing many precious data for parameter estimation. But, owing to intricate geological and engineering factors, the fractures in reservoirs are asymmetric and heterogeneous, which brings a great challenge for fracture estimation.

To improve this situation, coupling the deep learning (DL) approach and field practices, we established a surrogate model for non-uniform fractures at one stage based on deep Bi-directional LSTM model. First, a well testing model containing three distinct flow regions is developed, namely (1) heterogeneous hydraulic fractures, (2) the inner region affected by hydraulic fracturing, and (3) the outer region without stimulation. Laplace transformation method are used for model solutions. Then, with the model solutions, a surrogate model based on deep bidirectional LSTM is built for improve computational efficiency. The results show that the model can effectively reduce the early prediction error of pressure derivative, and the average relative prediction error is 1.67%. Finally, model verification was shown by comparing with the results from traditional well testing model. The results show that the calculation speed of the surrogate model is three orders of magnitude higher than that of the well test model, which helps to efficiently evaluate the fracture parameter in complex fracture system generated by large-scale fracturing treatments in shale reservoirs.
Experimental Study of Shape Memory Sand Control Screen
Authors: Ai Shuang , Duan Youzhi , Chen Yashu , Gao Chen , Rached Rached
Published: February 2022

Shape memory sand control screen completion based on shape memory polymer not only has the advantages of simple process and easy to run in hole, like independent screen, but also can achieve the sand management effect of gravel filling. Therefore, shape memory sand control screen has wide application prospects. However, since the shape memory material is temperature-sensitive, a large number of laboratory experiments are needed to evaluate its expansion, seepage and sand retaining capabilities, as well as optimize the polymer system and screen structure.

A performance evaluation experiment system for full-size shape memory screen prototype was developed. The device can describe the parameters of the shape memory screen during the expansion process and after expansion in real time and quantitatively, such as permeability, outer diameter and residual stress. The expansion behavior of screen prototype is controlled by step heating the passing through fluid to simulate the screen run in hole operation. 60 sets of experiments were carried out using the device. The expansion performance, seepage performance and sand control performance of shape memory screens were evaluated. Shape memory polymer formulation and screen structure are also optimized.

The research shows that the optimized shape memory sand control screen densely filled annulus and effectively supports the wellbore after expansion. The permeability of the expanded screen can be up to 35µm2, the displacement pressure difference can be less than 1kPa, and the sand control precision can be up to 0.061mm. Therefore, shape memory sand control screen can be used for sand control completion of oil and gas wells with limited well site conditions such as long horizontal wells, complex wells and offshore wells.

This paper presents an experiment device to evaluate the performance of shape memory screen, the dynamic expansion behavior is described during the expansion process and after expansion in real time and quantitatively.
Adding a New Lease of Life to a Sub-Hydrostatic Hydraulically Fractured Gas Well Using Coiled Tubing with Real-Time Telemetry
Authors: Pooniwala Shahvir , Brohi Imad , Waheed Arshad , Khan Abdul Muqtadir , Hamidon Zahaezuani Rafiq
Published: February 2022

Post-fracturing cleanup and production revival in sub-hydrostatic wells can be challenging. The complexity is amplified in sub-hydrostatic multistage horizontal wells because, by the time the fracturing treatment is concluded, the gas phase of the energized fracturing fluids used during the initial stages of the fracturing treatment dissipates. In the subject sub-hydrostatic well, coiled tubing (CT) with a real-time telemetry system was utilized over a standard nitrogen lifting intervention utilizing conventional CT to revive a hydraulically fractured well due to its capabilities to enable real-time decisions using live bottom-hole data.

Acid fracturing using an energized fluid treatment was conducted in the subject gas well completed with a multistage open-hole completion system using isolation packers and sleeves. As the subject well was sub-hydrostatic, it was decided to utilize the CT with real-time telemetry system to gain value from its associated downhole parameters during the cleanup phase to alleviate the chances of successfully lifting the well.

The well was placed in an area with prolific offset producers; hence, there were high production expectations from this well. A review of the well indicated a decreasing trend of reservoir pressure from heel to toe of the lateral, possibly contributing to lower stresses and potential crossflow between stages. Hence, the diverter concentrations and volumes per stage and nitrogen rates were maximized for each new fracturing stage to attempt to create new fractures. Considering the challenges with the well, it was essential that the N2 lifting operation parameters should be optimized to enhance drawdown. It was decided to utilize CT with a real-time telemetry system to control drawdown parameters better and maximize the possibility of success. Real-time downhole pressure measurements were utilized to accurately identify the fluid gradient followed by real-time evaluation and monitoring of the well behavior during N2 lifting operations. The real-time downhole data collected enabled on-the-fly intervention optimization leading to transforming the well into an economic producer.

The integrated post-treatment analysis workflow provided a robust insight into fracture treatment design and evaluation, reservoir imbibition perspective, openhole completion practices, and the importance of real-time telemetry for challenging interventions. The lessons learned that are presented in this paper could act as a guide to contribute to operational efficiency enhancements and cost savings in other projects.
Case Study: Lessons Learned in Attempting to Restore New Well Productivity Via Solid Propellant Technology and Dynamic Underbalance Stimulation
Authors: Dasuki Nurul Ain , Reekhi Gurveen Singh , Bakar Hasmizah , Tunku Abdul Muthalib Tunku Indra
Published: February 2022

In Field A, recently drilled wells D6, D7 and D8 penetrated at reservoir of good quality sands. However, the production rate declined rapidly within a year after wells kicked off. In an effort to restore new wells productivity, solid propellant technology stimulation and dynamic underbalance stimulation were evaluated for their effectiveness in permeability improvement. The candidates for solid propellant technology and dynamic underbalance stimulation were selected based on a screening workflow. Pressure data was retrieved from pressure downhole gauge to confirm skin buildup post production. The sources of production impairment were then investigated from laboratory analysis of core sample. While waiting for the results of laboratory analysis, solid propellant technology and dynamic underbalance stimulation were applied as quick solutions due relatively cheaper cost than chemical stimulation. Solid propellant technology was chosen for Well D8 whereas dynamic underbalance stimulation was selected for Well D6 and D7. Post solid propellant technology at Well D8, tubing head pressure and production rate slightly increased and sustained. On the other hand, dynamic underbalance stimulation at Well D6 and D7 showed positive results as tubing head pressure and production rates were improved. Unfortunately, production gain from dynamic underbalance at Well D7 only lived for a month before seizing to flow. The implementation of solid propellant technology and dynamic underbalance stimulation were successful to improve production performance for a short period of time. Both stimulation strategies were deemed to be repeated and improved to bypass near wellbore damage for these wells. This paper presents on the challenges and lessons learned that will be applicable to oilfields which are having similar situation to improve well productivity via mechanical stimulation.
Data-Driven Model for Measuring Hydraulic Fracturing Efficiency by Utilizing the Real-Time Treatment Data
Authors: Zhukova Kseniia , Antonic Miroslav , Soleša Mišo , Camber Dragan
Published: February 2022

The paper presents a practical tool for hydraulic fracturing efficiency evaluation. The tool is based on a data-driven approach that helps in interpreting real-time data. Based on the hydraulic fracturing (HF) job monitoring, statistic metrics and key performance indicators (KPIs) are generated to be valuable input for further designs and identification of potential savings in operation.

Machine learning (ML) algorithms are proposed to reduce the tedious work of completion engineers by automatically classifying each treatment schedule's timestamp and assigning the stage label. For operation stages classification Support vector machines and neural networks algorithms are used. These models are trained and evaluated on real-time treatment datasets. After automatic stage recognition, relevant statistic parameters are calculated, enabling advanced data analytics. Detailed analysis of historical data allows to identify the areas for improvements and set new best practices.

The first research objective was to gather data from various companies and structure them under the same template to conserve the most critical information gained during the hydraulic fracturing job. Afterwards, the data are preprocessed and labelled by using signal processing routines that significantly decrease the labelling time. The labels or classes are used to define different stages that can be distinguished during the treatment. Finally, the goal is to decrease the necessary time for data labelling. Therefore, two multiclass classification models (Support Vector Machines (SVM) and Neural Network (NN)) are built and evaluated. Based on evaluation metrics, both models resulted in high accuracy and reliable results. However, the SVM model resulted in slightly higher accuracy and an F1 score. The key value of these models is that they provide a computational method to extract a pumping schedule from hydraulic fracturing time-series data automatically. Also, these models allow conducting post-job analysis and choosing the proper pump schedule for a future HF treatment based on previous experience. This past-job analysis could contribute to the effectiveness of future operations by utilizing the materials and fluids more efficiently.
Flow Pattern Recognition in a Rotating Centrifugal Pump via Inflection Characteristics of the Performance Curves
Authors: Li Yuanyuan , Zhu Jianjun , Cao Guangqiang , Zhang Yongxue , Lu Yingda , Lu Bo , Zhu Haiwen
Published: February 2022

Of significant importance to multiphase flow, the gas-liquid two-phase flow pattern is extremely difficult to characterize in centrifugal pumps, where the impeller rotates at high speeds shrouded by the steal-made nontransparent casing. How to observe the flow patterns inside the rotating impeller has drawn considerable attention. In this study, an indirect flow pattern recognition approach via inflection characteristics of H-Q performance curves in a centrifugal pump is proposed and verified by both experiments and numerical simulations. An acrylic-made transparent impeller was employed to conduct experimental testing and visualize the internal two-phase flow patterns by a high-speed camera. To better illustrate the two-phase flow structure, the three-dimensional (3D) numerical simulation was performed and compared with visualization experiments. The preliminary results reveal that the inflections on the pump's H-Q performance curves can be regarded as the flow pattern transition boundaries under various flow conditions.
Physical Testing of a High-Speed Helico-Axial Pump for High-GVF Operation
Authors: Ejim Chidirim Enoch , Xiao Jinjiang , Lee Woon Yung , Zabala Wilson Andres
Published: February 2022

High-speed rotordynamic pump operation for downhole or surface production is required and also beneficial to handle very high gas volume fraction (GVF) flows. Operating speeds of these pumps can be in excess of twice those of conventional pumps. This study presents results showing a high-speed helico-axial pump (HAP) can operate satisfactorily at intake GVFs up to 98%. The findings increase capabilities of field engineers and operators to boost and maximize production from high gas-content wells.

The HAP tested had a housing outer diameter of 4.00-inch and operated at a rotational speed of 6000 revolutions per minutes (RPM). Air and water were the test fluids with the water volume flow rate held constant while the air volume flow rate was varied. The liquid and gas volume flow rates varied from 63 to 143 barrels per day (BPD), and 549 to 3238 BPD, respectively. Intake pressures varied from 14 to 76 psig, with average inlet temperature of 18°C. The corresponding discharge pressures and temperatures were recorded for each test point and observed for stable pump operation.

The results showed that the HAP had stable operation during the tests for intake GVF range from 84% to 98%. Pump discharge pressures for this range of high intake GVF varied from 21 to 89 psig. The corresponding differential pressures across the HAP all had positive magnitudes indicating that at such high-speeds, the HAP was still able to add energy to the fluid even with the high gas content at intake. Analysis at fixed intake pressure with varying GVFs showed that the discharge-to-intake pressure ratio decreased with increasing intake GVF. For instance, at 33psig intake pressure, increasing the intake GVF from 84% to 94% decreased the discharge-to-intake pressure ratio from about 1.27 to 1.20, respectively. It was also observed that tightening the clearance between the impeller and diffuser of the HAP increased the discharge pressure compared to when the clearance was loose. Furthermore, ensuring the upstream flow is properly conditioned also improved the stable operation of the HAP. Overall and in conclusion, running a HAP at high speeds in addition to optimizing certain features of the HAP can result in stable pump operation and enhanced pressure boosting in high-GVF flows.

This study mainly highlights the importance of operating HAPs at high speeds of up to 6000 RPM. Tightening clearances between rotordynamic components as well as tailored inlet flow conditioning are also additional features that enhance pressure boosting. This architecture opens up opportunities for field operators, and engineering personnel to maximize hydrocarbon production from their very high-gas content field assets, thereby increasing the economic bottom-line for the stakeholders.
Case Study of Gravity and Power Assisted Dump Floods Implemented in a Mature Oil Field
Authors: Mahmud Walid Mohamed , Abdussalam Omran Elhamali , Swissi Yousef , Elmabrouk Saber Kh.
Published: February 2022

Dump-flood is a powerful and convenient recovery technique that maintains a reservoir pressure where an aquifer and an oil leg are perforated in the same well. In gravity assisted dump-flood, GADF, water from a shallow waterbed above is injected by its own hydrostatic weight into an underneath oil bearing formation. In a power assisted dump-flood, PADF, the injection pressure from the waterbed maybe enhanced by utilizing electrical submersible pumps, ESP. In this work, both GADF and PADF were implemented in a mature depleted reservoir block for a quick pressure maintenance program. Three injectors were drilled and completed to have both the upper Gir and lower Gir intervals in communication. ESPs were installed in three wells to enhance the water gravity effect. Recovery Factor, RF, increased from 8.92% before the implementation of dump- flooding to 10.68% after the implementation with no signs of plugging or scaling in the reservoir. Reservoir pressure increased by 213 psi due to dump-flood implementation and oil production rate increased in one of the wells by 1629 barrel per day at an optimum choke size of 24/64 in. Dump-flooding is an excellent alternative to conventional water injection as the pilot injectors significantly stopped rapid pressure decline and improved production rates.
Experimental and Numerical Analysis of Thermal EOR Recovery Schemes for Extra-Heavy Oil of the Oykino-Altuninsky Uplift of the Romashkinskoye Oilfield
Authors: Pituganova Anastasia , Nassan Taofik , Amro Mohd , Minkhanov Ilgiz , Varfolomeev Mikhail , Bolotov Alexander
Published: February 2022

Crude oil production from conventional oil reservoirs is declining owing to heavy exploitation to meet the global energy market demand which is growing on a yearly basis. Unconventional oil resources, e.g. extra-heavy oil and bitumen, can compensate for this decline if appropriate enhanced oil recovery (EOR) methods are developed to enable economic flow from these resources. The main objective of this study is to set the best practice for the extra-heavy oil production of the Oykino-Altuninsky uplift of the Romashkinskoye oilfield (Tatarstan Republic, Russia). A series of experimental tests are applied on a real unextracted unconsolidated core sample from Romashkinskoye oilfield where the viscosity of the crude oil is above 600,000 cP at reservoir conditions. Different recovery schemes are tested experimentally and sequentially, namely: water flooding, hot water flooding, steam flooding, and finally in-situ combustion (ISC). Furthermore, the complete experimental run is simulated by a standard nonisothermal simulator and the results are compared to the experiments. On contrary to what was expected hot water at 100°C didn’t achieve any recovery from the sample and steam injection recovered only 11,5% of OOIP. ISC-is also known as fire flooding-attained the best recovery which reached 45% after steam flooding. Complete SARA analysis of the original oil and produced oil by steam and ISC is implemented to understand the mechanisms of each process. Numerical modeling is applied to the corresponding laboratory experiments and the results for water, hot water, and steam flooding were in good agreement with the experimental results while the in-situ combustion simulation showed a better recovery factor than experiments. The laboratory and numerical experiments will improve our understanding of the recovery options of Oykino-Altuninsky uplift of the Romashkinskoye oilfield and help the developers to choose the best production sequence for this oilfield particularly. Moreover, the experiments will provide inputs for the field-size numerical model after running more experiments on unconsolidated and consolidated cores.
A Non-Intrusive Production Optimization Technology for Surveillance of Gas Lift Wells
Authors: Tyagi Himanshu , Peacock Larry
Published: February 2022

This paper outlines a strategy to address the complexities involve in well surveillance and production optimization of gas lifted wells which operators around the world face in the quest to maximize production. Recent enhanced software-based analysis, designing and optimization has proved to be an effective tool in enhancing rate of production from an existing gas lifted well.

This technology incorporates introduction of a small volume of CO2 into the injection line and then measuring CO2 concentration via a sensor connected to wellhead tree, flowline or well test separator. Injection pressure and injection rate during the trace integrate with the well and valve modeling to determine the depths of each injection observed.

A pilot project on twenty wells of a major operator in the middle east exhibited a significant improvement in well performance with an incremental gain of 2000 bopd. One of the greatest strengths of this approach is that there is no need to shut-in or run any type of well intervention, resulting in greatly reduced risks, not only to field personnel but also to the well itself. Typical surveillance approach in assessing the health of the gas lifted wells is to deploy flowing gradient survey in tandem with surface well test. However, this historical technology has limitations in investigating prolific wells due to its current well mechanical condition, slugging nature, slim-hole completion design and dual strings design well environment. Application of this technology has broken the barrier in evaluation of these wells. It provides an efficient means of snapshotting the downhole issues beyond the capability of standard pressure and temperature surveys.

This paper considers multiple scenarios that help revive and elevate a potential hydrocarbon source and recommends suitable actions which allow production engineers to analyze performance of an oil well. With the increased complexity of mature fields, each next step to improve recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.
Increasing ESP Lifetime by Employing Novel Non-Corrosive Acid System for Scales Removal
Authors: Gamal Hany , Elkatatny Salaheldin , Al-Majed Abdulaziz A. , Al-Afnan Saad , Bahgat Mohamed
Published: February 2022

The scales precipitated on the electric submersible pump (ESP) will lead to trapped heat, lower the motor's cooling capacity, decrease the pump lifetime, and finally pump failure. Removal of oil field scales commonly requires low pH acid that can cause corrosion, hydrogen sulfide evolution, ferric and ferrous hydroxide precipitation, iron sulfide as a by-product, and/or sulfur precipitation. Scales typically occur in the near wellbore, tubing, downhole pumps, and surface equipment. A mineral deposition is widespread with a change in pressure, temperature, pH, and incompatible mixing between injected seawater and formation water.

This paper presents a new scale dissolver that is non-corrosive and has a high scale dissolution performance for barium sulfate scales. The study explains a series of comprehensive experimental lab tests such as X-ray diffraction (XRD), X-ray fluorescence (XRF), brine compositional analysis, fluid compatibility and stability, solubility test, precipitation tendency for the dissolved solids, and corrosion test to evaluate and simulate the field application of the new dissolver using two field scale types that mainly contain barium sulfate (BaSo4) scales.

The obtained successful results indicated that the novel dissolver had a great dissolution efficiency for two real barium scale samples as the results showed that the dissolution rate recorded 91.3 and 78.4 % at 90 °C for samples 1 and 2 respectively. The novel dissolver showed a very low precipitation tendency for the scale dissolved solids (1.9 and 3.2 % for samples 1 and 2 respectively). Without any additives of corrosion inhibitors, the corrosion rate was 0.00376 lb/ft2 at 1000 psi and 50 °C for 6 hours.

The obtained successful results will help to dissolve the barium sulfate scales, maintain the ESP performance, increase the lifetime, and save extra cost for the pump operational problems due to scale precipitations.
Rejuvenating First Shale Gas Field of China by Introducing Innovative and Tailored Casing in Casing Cementing Solutions
Authors: Liu Yaowen , Li Yuanzhao , Shen Jincai , Wang Bin , Zhang Chi , Zhao Kun , Ming Yue , Liu Zhongjun
Published: February 2022

China discovered Fuling shale gas field in 2012. The production dropped dramatically for early drilled wells with the time. Refracturing the wells to maintain production is a must to keep the field economically viable. A new method of cementing a smaller inner casing inside legacy production casing and then plug-and-perf fracturing was executed and the production was rejuvenated.

The procedure consists of well kill, wellbore cleanout and reaming, cure losses and then cementing. The wellbore re-construction process will isolate all existing perforations in the wellbore, and it can pass the pressure test for fracturing. The legacy wellbore is 5.5 inch size and a specialized 3.5 inch semi-flush joint casing was selected as new production string. A dependable cement barrier in this extremely tight annulus is required to carry on future re-fracturing operation. 2D hydraulic simulations and computational fluid dynamic was performed to optimize slurry density, rheology, and the method of cement placement. The cement mechanical property is enhanced to withstand the high pressure of fracturing. The top of cement in the annulus will be above the topmost existing perforation. The remaining 3.5 inch casing above the designed depth was disconnected and pulled out.

The wellbore was cleaned, and the losses were treated prior cementing. Tailored ceramic centralizers were installed on the casing surface to achieve optimum stand-off. The centralizer's friction factor is low to casing running to bottom successfully. A low rheology slurry tailored for optimum mechanical properties of fracturing operation was pumped, and the cement returns to designed depth were noted. The casing string disconnected at designed depth and pulled out successfully. After waiting on cement, the wellbore passed pressure test. Cement bond log showed excellent results and the top of cement reached the designed depth. The stage fracturing operation was performed with no issues of wellbore integrity.

A typical procedure of casing-in-casing cementing were recognized. Tailored slurry and centralizers design helped to achieve zonal isolation objective in the low clearance Casing-in-Casing cementing. The critical wellbore re-construction objective achieved and well was re-fractured with substantial increase in production.
Lessons Learned from a Case Study of Downhole Microseismic Mapping in the Southern Sichuan Shale Gas Play
Authors: Yue Wenhan , Wang Xinghao , Chen Juan , Tang Jie , Zheng Guangjie , He Long
Published: February 2022

A real-time downhole microseismic mapping technique was recently used in the southern Sichuan shale gas development. The case study presented illustrates this technique and analyzes the results, from the geological evaluation through the engineering solution, for a typical H24 pad fracturing.
High Salinity Water Flooding in Carbonate and Clastic Rocks: Qualitative and Experimental Analysis
Authors: Al-Ibrahim Hussain , Taq Ali , Alyami Ibrahim , Aldarweesh Sajjad
Published: February 2022

Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential and thus maintaining required injectivity. Also, injected water should be compatible with both rock and formation fluids minimizing risk of permeability impairment or flow assurance problems during the production phase. Assessing water quality is a prime step to prevent scale precipitation, fine migration and any negative impact resulting from water/rock interactions.

Extensive experimental studies including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the effect of high (salinity, sulfates and bicarbonates) water samples on clastic and carbonate core plugs. The impact of rock clay content, fine migration and scale deposition on impairment of rock permeability was investigated. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less effect on formation permeability. Experiments were conducted at temperatures up to 200°F and pressure 3,000 psi. Formation damage mechanisms were investigated using XRD and ESEM methods on precipitated scale due to fluid/fluid and rock/fluid interactions.

HT/HP compatibility test results indicated that some of the examined water mixtures precipitated iron compounds when exposed to air. Oxygen scavenger was added to some water mixtures to halt iron precipitation before injection into the carbonate and clastic core plugs. Coreflood experiments showed permeability reduction in some of the core plugs, which was attributed to the precipitation of iron oxide/hydroxide compounds as, indicated from ESEM and XRD analysis. High sulfates and high bicarbonates content of some of the water mixtures precipitated compounds that contain both on the face and deep inside some of the tested plugs leading to reduction in permeability.

This paper presents a qualitative and experimental water flooding analysis study conducted to assess interaction of different water/water mixtures on clastic and carbonate core plugs. It also investigates different formation damage mechanisms associated with water injection. It investigates interaction impact of water mixtures with examined core plug permeabilities.