bluuebunny/crossref_metadata_2025_split huggingface dataset:
Utilizing PulseJet Technology to Enhance Water Injectors Injectivity
Authors: Al Ruqaishi Abdullah Saud , Al Ghammari Ahmed , Ferdiansyah Erik , Al Harthi Najeeb , Plotnikov Alexey , Zazuliak Oleg , Inamov Noman , Hryhoruk Oleksandr 
Published: October 2022

Abstract
In one of north Oman matured carbonate water flood field (Block A), acid matrix stimulation treatments are usually performed by Well and Reservoir Management team (WRM) to enhance inflow performance. These treatments are deployed through Coiled Tubing Unit or bullheaded by pumping units. More than eighty percent (80%) of them are performed in water injection wells to remove near wellbore skin mainly due to calcium carbonate scale with hydrocarbon layer at the scale surface. 15% to 20% HCl simple acid recipe with or without chemical diversion are used as main fluid, with foam or gel acid as main chemical diverter. Recent treatments with 15% HCl have shown communication between treated injectors to nearby oil producers (short circuiting), suspected due to induced fracture by acid matrix stimulation treatment. Increasing in the demand of operational performance by eliminating unnecessary risk of inducing short circuiting between the water injector and oil producers has given birth to a new approach to enhance well injectivity.
The PulseJet technology trial is intended to remove near wellbore formation blockage using Surface Pulse Generator [5] without involving acid chemicals; hence it is expected to have less risk in inducing fracture to the formation. With no acid chemicals required, it means less HSE risk to the personnel. In addition, this technology uses existing energy of formation pressure, therefore can be applied in very low to nil injectivity, if formation pressure is high enough to remove the blockage. Low (less than 80 ltr/min well injectivity) to nil injectivity, usually cannot be efficiently treated with bullheading technique, therefore more expensive unit, i.e CTU, is required to deploy stimulation treatment in this type of wells. If this trial is successful, this can help to minimize CTU requirement hence will result in saving to the company.
This technology was trailed in 22 vertical water injectors where improvement of initial injectivity have been observed and 60% of them demonstrate sustained injectivity to more than 300 days. All treatments were performed safely with eliminating the exposure of mixing and pumping corrosive 15% HCl acid of 1500 m3. Most importantly, our wells did not experience any short circuiting with the oil producers.
This paper describes the Pulsejet technology implementation as alternative to the conventional methods CTU or bullheading matrix stimulation. The candidate selection and execution procedure will be discussed including the lessons learned during this technology trails implementation.
State-Of- The Art Corrosion Inhibitor Development to Mitigate Pitting Corrosion in the Presence of Elemental Sulfur and Poly Sulfides in Sour Oil and Gas Systems
Authors: Obeyesekere Nihal U. , Dickey Douglas C. , Wylde Jonathan J. 
Published: October 2022

Abstract
The effects of elemental sulfur on the corrosion of mild steel is a serious problem in the oil & gas industry costing millions of dollars annually in lost production and assets.
Mitigating the corrosive effects of elemental sulfur on mild steel in the oil and gas industry is a challenge and finding a viable solution would provide a more cost effective and safer working environment and as well as be environmentally conscious. Currently, there are no highly effective products for elemental sulfur corrosion in the marketplace.
More than fifty new chemical formulations were blended and screened by rotating cylinder electrode method (RCE). These formulations were tested in the presence of 0.1% elemental sulfur in mildly sour conditions. The promising candidates were identified and tested again in the presence of elemental sulfur under the same mildly sour conditions.
The most promising candidates from the initial screening were then subjected to rotating cage autoclave (RCA) testing for extended periods of time in the presence of 0.1% and 0.15% elemental sulfur. The general corrosion rates were calculated via weight loss and the metal surfaces were examined under a high-power digital microscope for pitting and localized corrosion.
A detailed analysis of the above testing yields promising results. The results from the testing show that formulations mitigate pitting in environments containing elemental sulfur. In less harsh conditions, such as low chloride brines or low CO2 environment, formulations seem to provide excellent protection against general corrosion while mitigating pitting due to elemental sulfur. In more extreme environments such as harsh brines with elevated chloride levels, high hydrogen sulfide and CO2 levels, the formulations mitigate pitting but need further development in inhibiting general corrosion The best product currently developed inhibits corrosion and pitting in the presence of elemental sulfur in various conditions and performs well against elemental sulfur in more aggressive sour systems. We are currently improving the performance against elemental sulfur and developing chemistries to mitigate polysulfide induced corrosion in sour systems.
This paper describes the development of effective inhibitors for corrosion and pitting in the presence of elemental sulfur under sour conditions. This study focuses more on pitting corrosion due to the corrosive characteristics of elemental sulfur than on uniform general corrosion. The general corrosion with the selected inhibitor was highly mitigated and was less than 3.0 mpy while yielding excellent protection against sulfur induced pitting.
A Successful Milestone Accomplishment of Sour Gas Well Testing Operation
Authors: Alsenaidi Shemaisa Ahmed , Albadi Mohamed Mubarak , Ahmad Mubashir Ahmad , Dike Nnamdi Ahmad , Alsaadi Noura Ahmad , AlHosani Abdulla Ahmad , Ahmad Zeeshan Ahmad 
Published: October 2022

Abstract

Submission Summary
A successful achievement by ASR ADNOC onshore started by accepting the challenge of testing Ultrasour gas wells. We are taping on additional reserve by carrying out the appraisal testing of sour gas wells with high H2S that contain H2S ranging from 20 to 40 % and CO2 11% approximately that is creating multiple challenges during testing and tie in the well. And due to high H2S compounded with extremely high temp and pressure the use of conventional material is not possible thus, creating multiple challenging while testing the gas wells in ADNOC Onshore fields. Another milestone of this project is evaluating the exotic material selection for sour wells, as well as HSE protocol modifications and utilizing the existing facilities in order to reduce the CAPEX & OPEX for the production of highly sour gas using the blending studies development.
So, this project is an example of success story that successfully managing the ultra-sour gas wells with high temp and pressure safely during drilling, tie-in and well testing operations. And once its potential is untapped the additional TCF (Trilliant Cubic Feet) gas will be available for the future generations.
Injection Profiling for Intelligently Completed Wells Equipped with Fiber Optics
Authors: Adil Mohamed , Santhirasekaran Lingies , Arief Tham Nabilla , Seabrook Brian 
Published: October 2022

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

Abstract
Zohr field was discovered in 2015 by the Italian energy company Eni and is the largest ever natural gas found in the Mediterranean Sea, with around (30 trillion cubic feet) total gas in place. Belaim Petroleum Company (Petrobel) (JV with ENI) is the Egyptian Petroleum Corporation arm and the owner of the project. Production started in December 2017 and since then 18 wells have been drilled for production.
This paper describes the criteria for material selection of the production strings for Zohr’s deep-water gas producers and how pre-tested and approved cost-effective alternatives are available for such a top-class project. The paper details the qualification and deployment of glass reinforced polymer (GRP) Lined Tubing as an alternative to 28%Chrome tubing, including the testing work that has been performed, and the operational aspects of running the referred-to alternative in several deep-water projects.
The choice of Duoline lined tubing results from the need for a cost-effective solution delivering the same operational requirements of 28% Chrome production strings. And since the Duoline GRE system will be integrated with the steel tubing therefore this system has to be previously fully approved and certified by the manufacturing mill of the lined tubing so there would be not even minor modifications to the specifications and the sealing performance of the premium connections and tubing body.
The paper indulges into describing the laboratory tests and the field experiences of the Duoline Lined tubing system in various fields globally, where this system has been tested in severe operating conditions with elevated levels of H2S, CO2, Salinity, dissolved Oxygen conditions to investigate the capability and service limits of the fiberglass liner at different temperatures. In addition to mentioning the erosion tests that were performed, mechanical tests such as pressure loop and make & break tests, how these various tests ended with good results and its comparison to the exotic high chrome joints performance.
This fiberglass lined tubing system has been applied in gas production wells since the 1980s, and ENI has been utilizing this technology in their production and water wells since 2005 in the north Africa, middle east, Kashagan regions and Norway offshore wells. On the other side, the technology has been successfully used world-wide in more than 55,000 wells since 1960s in various applications besides gas production strings.
The paper will present the past experience of ENI with fiberglass lined tubing, the laboratory tests, the field experiences, the economic evaluation of implementing this system in such a high-profile project, In addition to the pre-qualifications performed on this system by the OCTG mills and approvals granted to integrate this technology with the patent premium connection joints.
Novel Organically Modified Nanoparticles Stabilized Emulsified Acid Paves Way for Productivity Enhancement in High Temperature Gas Reservoirs
Authors: Kalgaonkar Rajendra A , AlJama Majid , Cairns Amy J , Alali Eyad 
Published: October 2022

Abstract
Well stimulation of carbonate reservoirs is conventionally associated with the using of strong mineral acids such as hydrochloric acid (HCl). However, the heterogeneity of the reservoir as well as the fast reaction rate of HCl with the rock will lead to face dissolution rather than achieving deeper wormholes or longer fractures. A commonly used approach to slow down the acid/rock reaction rate is through the use of acid-in-oil emulsions. Unfortunately, the thermal stability of the emulsified acids is significantly impacted at high temperatures (+300 °F), which will result in poor penetration of the reservoir, thus reducing the treatment effectiveness.
This paper showcases the development and successful field application of an enhanced emulsified acid system for stimulating high-temperature carbonate reservoirs. The new system utilizes organically modified nanoparticles with the emulsified acid to form a solid stabilized emulsion. The unique morphology of the nanoparticles along with their selective organic modification facilitates formation of a high temperature stable emulsified acid system with lower viscosity compared to conventional emulsified acids. The low viscosity reduces surface pumping pressures leading to higher pumping rates for deeper reservoir penetration. The new system can work with HCl concentration up to 28% and temperatures up to 325 °F.
We present here the systematic developmental study and field trial results for the organo-modified nanoparticles stabilized emulsified acid system, targeting high temperature carbonate gas reservoirs. Several laboratory performance tests were judiciously undertaken to compare the performance of the new emulsified acid with conventional systems. Experimental studies including rheological characterization, thermal stability, corrosion mitigation and formation damage profiling are reported. The new emulsified acid displayed lower viscosity, enhanced stability at high temperatures, corrosion loss within industry acceptable limits, superior stimulation effectiveness and minimal formation damage compared to conventional emulsified acid. Stimulation treatments using the enhanced emulsified acid showcased excellent flowback performance with no reservoir damage.
The new organo-modified nanoparticles based emulsified acid system not only demonstrated enhanced temperature stability, but also minimized the surface treating pressure facilitating higher pumping rates and deeper reservoir penetration resulting in excellent stimulation of carbonate reservoirs.
Assessing 3D Bedding Plane Effects on Well Performance in a Field-Scale Unconventional Reservoir Model Using EDFM
Authors: Leines-Artieda Joseph Alexander , Fiallos-Torres Mauricio Xavier , Useche Franklin , Fonseca Rahul-Mark , Mahmoud Salah El din , Alqaydi Maryam , Alharthi Amena , Al Hashmi Abdulla , Ramsay Travis , Al Bannay Aamer , Song Xueling , Yu Wei , Miao Jijun 
Published: October 2022

Abstract
Bedding-plane slip effects during hydraulic fracturing have recently gained interest in unconventional plays due to their influence in hydraulic fracture growth in vertical and horizontal directions. However, most of the current workflows cannot fully model field-scale sub-horizontal orientation of bedding planes because of complications with gridding techniques, or due to simplifications related to the use of 2D models. These challenges have motivated the assessment of 3D bedding plane interactions on well performance using the embedded discrete fracture model (EDFM) technology for field case scenarios.
An efficient hydraulic fracture propagation model is used to model hydraulic fracture growth in the presence of bedding layers. The model captures shear slippage at the bedding layer interfaces and corrects the calculated stress intensity factor to account for height containment. A hydraulic fracture model, constrained by geomechanical information, is built in a corner point grid. Resulting hydraulic fracture geometries and identified bedding layer fractures are transferred to EDFM by using a 3D bedding plane generator, which places sub-horizontal polygons across the well trajectory, honoring its orientation and geometry. To locate the spatial position of bedding layers, geostatistical constrains, core analysis and petrophysical interpretations – including well image logs – can be taken into account. Lastly, a reservoir simulation model is built to evaluate the effects of bedding planes on well performance.
3D effects of bedding planes in a shale gas reservoir were captured in a field case scenario using numerical models. Higher contribution to production was observed in the results of this study. The main reasons are larger fracture lengths generated along the pay zone caused by bedding plane influence in the fracture propagation process and shear slippage along bedding plane fractures, which create a larger effective conductive surface area. When modeling bedding planes, computational efficiency is substantial due to the EDFM method, preserving spatial orientation and geometry of each bedding plane.
Direct assessment of bedding plane properties is provided, which highlights the importance of capturing their interactions with hydraulic fracture growth and well performance. A seamless integration of bedding plane models can be achieved in an efficient workflow that provides key lessons for future fracture design and well spacing optimization.
Integrated Concept Analytics and Development Optimization Under Uncertainties
Authors: Shao Yufen , Li Jizhou , Seow Ming–Jung , Zhu Yuzixuan , Guo Yuanyuan , Pradhan Daman , Malpani Deepak , Furman Kevin 
Published: October 2022

Abstract
Decision-making complexity in the oil and gas industry has risen dramatically in recent years, especially in consideration of uncertainties related to geopolitics, policies, marketing, subsurface resources etc. To enable decision making with the best quality opportunities and projects, we are developing an integrated suite of machine augmented mathematical technologies to recommend holistic decisions for concept selection and development planning under uncertainties. Our ongoing technology development is progressing a set of prototypes and use cases including: 1) AI-based uncertainty handling technologies aiming to detect uncertainties, quantify impacts, and translate to influence factors for decision-making (e.g., IRR, cost); 2) Decision-driven surrogate reservoir models approximating subsurface dynamics to enable rapid concept screening; 3) a set of mathematical optimization-based decision models in the form of mixed-integer linear programs (MILP) to provide solution alternatives to address different business challenges under uncertainties. We demonstrate that the use of systematic technical applications combined with human interaction can improve the decision quality significantly by considering all influence factors, searching through the entire decision space, and recommending a range of alternatives for business users to consider with minimal bias. These technologies have been designed to plug into existing processes and platforms to accelerate technology adoption and usage.
Impact of Viscous Instabilities on WAG Displacement
Authors: Skauge Arne , Skauge Tormod , Sorbie Kenneth Stuart , Bourgeois Marcel Justin , Chang Paulo Lee Kung Caetano 
Published: October 2022

Abstract
In earlier studies, we have investigated water-oil displacement at adverse mobility ratios, and the impact polymer may have to improve the oil recovery. This paper addresses gas-oil displacement which is inherently an unstable displacement process, due to the low phase viscosity and density of the gas phase. In this work, a systematic study of viscous fingering for gas injection and WAG is performed as a function of rock heterogeneity, viscosity ratio, and density difference. The results of these studies aim to improve the design of gas injection and WAG to optimize sweep and total oil recovery with least possible amount of gas recycling.
The numerical modelling has been carried out using commercial reservoir simulators. The methodology for describing viscous fingering is similar to that presented by Sorbie et al. (2020), where a 4-stage approach was proposed; viz. (i) choosing the form of the fractional flow curve, (ii) from fractional flow deriving a set of relative permeability curves which gives the maximum total mobility function, (iii) establishing an appropriate random correlated permeability field and (iv) simulating the process with a sufficiently fine grid.
Simulations have been performed with fine grid 2D, using variations in viscosity ratio and phase densities. The impact of heterogeneity has been studied by varying the local distribution of rock permeabilities.
Here we use experimental data from different sources to determine WAG parameters. Horizontal gas injection gives viscous fingers, and the unstable flow leads to very early gas breakthrough. We studied the influence of gravity on formation and development of viscous fingers. By combining experimental data with simulations, we show that viscous instability of the gas-liquid front can be captured in simulation models based on relative permeabilities gained from gravity stable core floods.
Numerical simulation studies confirm the recommendations and show the benefit of altering the core positioning. The simulation of generic core flow experiments was performed by using mm scale grid cells and heterogeneous permeability fields with rather short correlation lengths.
In immiscible gas displacement, the finger pattern appears to be mostly dominated by the viscosity ratio. However, these observations will mainly apply in the viscous limit when the other forces, capillarity and gravity, are small. Trapped gas during WAG injection is found to dampen the gas fingers, even in a 2D cross-sectional case. In a full 3-D case the extent of the three-phase zone adds to the differences between the WAG and gas injection cases.
Simulation studies show examples where stabilized flow relative permeability can model unstable displacement in fine grid models. The unstable horizontal oriented flow gives early gas breakthrough and viscous fingers dominate the flow. Shorter WAG cycles seem to be beneficial to optimize oil recovery and reduce gas recycling.