bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on a Novel Comprehensive Numerical Simulation Model of Self-Generating Acid Fracturing for Ultra-Deep Carbonate Reservoir in the Shunbei Oilfield
Authors: Ren Jichuan. , Xu Peixuan. , Guo Jianchun. , Zhao Bing , Xie Xinjie , He Le , Gou Bo 
Published: April 2024

Summary
China's continental marine carbonate rocks are rich in oil and gas resources, but the reservoir conditions are poor. Acid fracturing is the main technological measure for the stimulation of carbonate reservoirs at home and abroad. Due to the high temperature of carbonate reservoirs in China, the acid-rock reaction speed of gelled acid and other commonly used acid systems in the field is fast, so that the effective distance of acid is short (50-70m), the acid etched fracture conductivity at the distal end of the fracture is low, and the deep penetration transformation cannot be realized, which has a great influence on the stimulation effect of the reservoir. In this paper, a numerical model that can accurately describe the whole process of self-generating acid reaction under in-situ conditions is established. At the same time, fracture propagation, flow field, temperature field, concentration field and reaction process are coupled. The simulation analysis of self-generating acid concentration distribution, etching characteristics and effective acid etching fracture length under different influencing factors is carried out to understand the self-generating acid, etching law and main control factors, which provides a basis for the optimization design of self-generating acid fracturing process. The results show that (1) Temperature is the main factor affecting the acid generation rate of self-generating acid. The effective acid etching length at the distal end increases with the increase of temperature, the effective acid etching length at the proximal end decreases with the increase of temperature, and the overall effective acid etching length increases. Under the condition of 10 mD permeability, high displacement plays a role in promoting the effective acid etching fracture length, (2)The higher the matrix permeability, the smaller the effective acid etching fracture length.(3)Under the condition of small acid amount (300 m3) and medium acid amount (500 m3), the displacement has little effect on the effective etching fracture length. Under the condition of large acid amount (800 m3), the displacement has a certain promoting effect on the distal effective etching fracture length. (4)The greater the amount of acid injection, the greater the distal effective acid etching fracture length.
Best Practices to Predict and Recognize Liquid Loading and to Forecast and Maximize Intermittent Production
Authors: Veeken C. A. 
Published: April 2024

Abstract
Eventually, mature gas wells start liquid loading as their gas rate declines due to reservoir pressure depletion. That triggers a period of intermittent production until stable production can be restored by deliquification. This paper describes how to predict and recognize the onset of liquid loading, and how to forecast and optimize the associated intermittent production. These best practices can be used to minimize liquid loading deferment and to schedule deliquification measures.
Practical Appraisal of Sulfonated Polymers for a Sour High Salinity and Heavy Oil Reservoir in Kuwait to Fast-Track Field Implementation
Authors: Al-Murayri M. T. , Hassan A. , Alajmi N. , Andrianov A. , Garcia J. , de Kruijf A. , Liu E. , Li E. 
Published: April 2024

Abstract
Using high-salinity effluent water for polymer flooding is a strategic endeavor to mitigate water-handling constraints and debottleneck oil production. This study sheds light on the workflow that was adopted to select appropriate polyacrylamides with AMPS/ATBS monomers to improve polymer stability, particularly under harsh salinity, hardness and H2S levels. Molecular weight optimization was important to rationalize polymer selection for two stacked reservoirs with different permeabilities to reduce polymer retention and maximize oil gains.
Extensive laboratory evaluation followed by a one-spot EOR pilot and a regular 5-spot pattern confirmed the effectiveness of polymer flooding for the Umm Niqa Lower Fars (UNLF) sour heavy oil reservoir, using high-salinity effluent water with Polymer A, mainly targeting the F2 layer. This instigated further investigation on the feasibility of polymer-flooding for the UNLF F1 layer (i.e. F1), overlying the UNLF F2 layer (i.e. F2), using the same wells, configuration, inlet water and surface facilities. Two new polymers with different molecular weights, but similar chemistry to that of Polymer A were lab-evaluated on a fast-track basis covering rheology, injectivity, oil recovery, polymer retention, resistance factor, residual resistance factor and polymer stability.
F1 has higher oil viscosity, lower permeability and shallower depth compared to F2. This necessitates optimizing polymer molecular weight and concentration to establish good injectivity, optimize polymer concentration and reduce polymer retention. Following F2 field implementation using polyacrylamide Polymer A, two lower molecular weight polymers were identified for F1. Laboratory results using high-salinity effluent water and reservoir temperature showed that polyacrylamide Polymer B is better-suited for F1. This was evident from polymer retention and injectivity data. The optimal polymer concentration for field implementation has been defined using reservoir simulation to ensure commercial throughput and maximize oil gains, while safeguarding caprock integrity.
Polymer-flooding is time-sensitive and the incremental benefits of it tend to diminish with time. This study demonstrates the feasibility of fast-tracking laboratory evaluation to select appropriate polymers for expeditious field implementation. Future work can focus on further optimization of ATBS/AMS content, polymer concentration, water treatment requirements, and well completion to concurrently target multiple reservoir layers with reduced surface footprint.
Production Strategy for Gas Cap-Oil Rim-Water Drive Reservoirs: A Case Study of the N Field, Mehsana Asset, India
Authors: Parth C , Hitisha D , Moatoshi A. O. , Sanket T , Dayal H. S. 
Published: April 2024

Abstract
This technical paper presents a production approach implemented in the N field, where a reservoir characterized by a gas cap, oil rim, and water drive posed unique challenges for efficient recovery. Typically, conventional reservoirs employ perforation in the oil zone to facilitate pressure maintenance through gas cap expansion and the water drive mechanism. However, in the case of the N field, production from gas cap resulted in movement of oil in the gas zone. Instead of traditional perforation techniques, the reservoir was produced through targeted extraction of the gas cap. This approach outlines the operational procedures employed, highlighting the significant oil production rates after substantial gas extraction and movement of oil in the gas zone with the geological interpretations. There are three layers in this area, K-I, K-II and K-III. K-III is majorly oil bearing while K-II has a thick oil rim and K-I has thin oil rim and major gas cap area. The well wise execution strategy of K-III, II and I have been explained in the paper. This production strategy led to reservoir management via chemical water-shut off jobs, production logging-based perforation optimization and liquid rate optimization.
Following this unconventional step, the oil migrated to the anticlinal top structure of the reservoir, enabling subsequent production of oil after production of gas cap gas and till now it has yielded recovery rates of greater than 40% with current oil production of 860 tpd. The findings of this study emphasize the importance of considering unconventional production strategies tailored to specific reservoir characteristics. The case of the N field demonstrates the potential for achieving improved recovery rates and optimizing the utilization of available resources in gas cap-oil rim-water drive reservoirs. The insights gained from this unconventional approach can contribute to the development of future production techniques in similar reservoir types, ultimately enhancing oil recovery and overall field performance.
Advanced Carbonate Acidizing with Optimized Retarded Acid to Reduce Matrix Acidizing Carbon Footprint
Authors: Ryan A. , Kamaletdinov B. , Araque G. , Arali V. 
Published: April 2024

Abstract
In pursuit of the 1.5°C climate threshold set by the Paris agreement above pre-industrial levels, achieving net-zero CO2 emissions by 2050 is identified as crucial. This necessitates leadership from the energy industries in formulating and executing sustainability development goals. Addressing all emissions sources is imperative for the success of this ambitious endeavor. The study investigates the application of an optimized dosage of a novel single-phase retarded acid (SPRA) fluid system to reduce the carbon footprint in stimulating horizontal extended reach wells targeting lower-permeability reservoirs in Middle East.
Hydrochloric acid (HCl), which is commonly employed in matrix acidizing for creating wormholes in carbonate reservoirs, faces challenges in achieving the desired productivity index due to rapid reactions at high bottomhole static temperatures. The development of SPRA, an HCl-based fluid with enhanced retardation factor, demonstrated superior wormhole penetration depth through the synergistic action of two retarding agents. Employing stimulation modeling analysis, this work investigated optimized SPRA dosage and demonstrated its superior performance over regular HCl acid in post-stimulation skin reduction and wormhole generation. In most of the SPRA applications, the performance of the stimulation treatment is still higher compared to the straight acid, even at reduced volume. Subsequent history matching exercises confirmed the generation of longer wormholes and the effective reduction of skin across the entire lateral section of the well.
Validation of simulation findings was achieved through flowback and production data collected after stimulation. The presented case studies demonstrate the implementation of the innovative SPRA fluid system, resulting in a significant reduction of up to 51%, equivalent to 274 metric tons of CO2 emissions throughout the entire value chain. This includes a 50% reduction in total acid volume and a substantial 67% decrease in flowback time. These findings underscore the considerable environmental and operational benefits of the SPRA fluid system in advanced carbonate acidizing of extended reach wells.
Novel Nanoparticles Based Stimulation Fluid Enhances Productivity in High Temperature Gas Reservoirs
Authors: Kalgaonkar Rajendra A. , Sahu Qasim A. , Malik Ataur R. , Ghazwi Mustafa A. 
Published: April 2024

Abstract
Emulsified acids are conventionally utilized in acid fracturing operations in tight gas reservoirs. Unfortunately, the thermal stability of the emulsified acids is significantly impacted at high temperatures (&gt; 300 °F), which will result in poor penetration of the reservoir, thus reducing the treatment effectiveness. Moreover, high viscosity of conventional emulsified acids often results in high friction losses limiting the pumping rate in acid fracturing treatments.
In this paper we demonstrate the development and successful field applications of enhanced acid emulsion system that incorporates surface modified nanoparticles. The unique morphology of the nanoparticles along with their selective organic modification facilitates formation of a high temperature stable acid system with lower viscosity compared to conventional emulsified acids. The fluid exhibited reduced pumping pressures leading to higher pumping rates for deeper penetration in multistage horizontal wells. 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 nanoparticles stabilized emulsified acid system, targeting high temperature carbonate gas reservoirs in multistage horizontal wells. 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 reservoir 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. The stimulation operation utilizing the enhanced acid emulsion showcased excellent flowback performance without indication of any formation damage.
The novelty of this paper is the development of the enhanced emulsified acid stabilized with the surface modified nanoparticles having a unique morphology. The main advantages of this enhanced acid system were its high temperature stability and lower friction pressure pressures facilitating higher pumping rates and maintaining continuous net pressure, thus, deeper reservoir penetration resulting in excellent stimulation of carbonate reservoirs.
Optimizing Underbalanced Coiled Tubing Drilling Monitoring Via Advanced In-Line Sensing AI Framework
Authors: Abu Alsaud S. , Katterbaue K. , Alshehri A. 
Published: April 2024

Abstract
Logging while drilling (LWD) technologies have been extensively developed and implemented to evaluate downhole rock and fluid properties. Nevertheless, sparsity of information, indirect measurements, and a challenging downhole environment are critical factors in obtaining accurate formation evaluation diagnostics. This is especially critical given the limited number of LWD technologies for underbalanced coiled tubing drilling (UBCTD). As such, forecasting formation patterns and drilling conditions from real-time surface in-line measurements on the return mud is a promising area that will significantly advance UBCTD monitoring capabilities. In this work, we present a noninvasive data driven approach by utilizing a series of inline sensors on the mud return to determine the characterization of fluids and rock cuttings. An advanced nonlinear autoregressive network was utilized for the forecasting of the solid and hydrocarbon concentrations based on the sensor derived in-pipe measurements. The measuring sensors comprise a range of inline sensors, including ultrasonic acoustic sensors, optical imaging devices, pipe resistivity sensors, spectral gamma ray sensors, flow meters, and viscosity sensors. The results demonstrate the strong forecasting capabilities of the nonlinear autoregressive network deep learning framework in determining solid and hydrocarbon concentrations and may support classifying rock cutting' types in real-time based on the measurement dataset. The test was conducted on synthetically realistic formation drilling data, which showed strong estimation capabilities and a high-performance score. Based on the test, we concluded that gamma rays, electromagnetic induction, optical, and acoustic sensing are the major principal components affecting the quality of the estimation. This deep learning framework is instrumental in the integration of LWD, measurement while drilling (MWD), advanced mud logging, and drilling parameter data to guide UBCTD operations and support real-time formation evaluation.
A Chemical Method of Achieving Uniform Stimulation Intensity Along Long Laterals in Horizontal Wells
Authors: Zebo Yuan , Huifeng Liu , Ning Xu , Song Jin , Ying Shi , Zhangxin Chen 
Published: April 2024

Abstract
To exploit a reservoir more efficiently, horizontal wells with long laterals are being drilled in many oilfields in the world. Uniform acidizing by bullheading is a challenge in these wells because the volume of acid that enters each segment tends to be different: larger at the heel while smaller at the toe. This further causes a non-uniform production profile which advances breakthrough of water.
In this paper, a method of using a temperature-sensitive viscous acid to achieve uniform stimulation profile is introduced. The acid is delicately designed so that the viscosity of it changes with temperature and the changing rate can be quantitatively controlled. As the acid flows in wellbore, the diffusion coefficient of H+ and therefore the acid-rock reaction rate gradually increases while it is being warmed by wellbore. A model describing the change of viscosity and H+ mass transfer coefficient is established and coupled with a wellbore heat transfer model.
The basic of this acid is hydrochloric acid but it is mixed with a special gelatinizer. The initial viscosity of the acid ranges from 60 to 1400 mPa.s at surface, depending on the concentration of gelatinizer. Its viscosity gradually decreases to 200 mPa.s with temperature increasing to 100 ℃.The leaking off velocity decreases from 2.0×10−6 m/s to 2.0×10−7 m/s accordingly, depending on the injecting time. And the acid concentration at the wall of wellbore increase by three times when the injecting rate doubles, also depending on the wellbore temperature and pressure. The acid-rock reaction rate is faster at toe than at heel, which just compensates the differences of acid volume allocation between toe and heel due to wellbore flow friction. A model describing the correlations between the acid viscosity, diffusion coefficient of H+, the concentrations of HCl, the injection rate and the temperature is generated. This model is coupled with an acid flow and reaction model and a wellbore heat transfer model and in the end a profile of H+ consumption along the lateral is predicted. With use of this model, by adjustment of acid formula and injection rate, a uniform stimulation intensity profile along the long lateral can be achieved. A well case is introduced to show the application of this model.
The dynamic temperature profile, the acid viscosity profile, the allocation of hydrogen ions as well as the equivalent wormhole lengths along the wellbore are all given in the paper. This paper introduces a chemical way to achieve uniform acidizing intensity in horizontal wells with long laterals without running in mechanical tools, reducing cost and leaving a good wellbore environment for future well interventions after treatment.
Determining Key Reservoir Parameters from Diagnostic Fracture Injection Test DFIT Conducted in a Disposal Well in the Bahrain Field Using Multiple Analysis Techniques
Authors: Konwar Lakshi , Bu Ali Y. Y. , Ali W. , Naira W. , Alawainati E. M. , Omar Matar 
Published: April 2024

Abstract
In the Bahrain field, wet sand waste/sludge mixtures generated from the Waste Management Sump Facility (WMSF) are stored in temporary storage areas. A well in a sandstone reservoir is identified for conversion to water disposal for waste management to dump around 3,000 barrels of NORM (naturally occurring radiative material) waste accumulated over the last 5 years. Estimating formation breakdown pressure and reservoir flow capacity is crucial for injection capacity estimation and safe injection in a disposal well. Step-rate test (SRT) and injection falloff have now become the standard practice to estimate formation breakdown pressure, reservoir pressure, and formation permeability. This paper focuses on the preparation of a NORM injector after a detailed review of geological, petrophysical, production, and reservoir engineering data of the sandstone reservoir in the field. An injectivity test using SRT followed by a pressure falloff test was conducted in the subject well to determine the injection rates and pressures required for injection of NORM waste. The paper presents the results of the step rate test (SRT) and both the before-closure and the after-closure analysis (ACA) of the falloff test conducted on the disposal well prior to design of SFI (slurry fracture injection process).
Besides conventional analysis, the SRT is analyzed using modified-Hall analysis (MDH) and injectivity analysis. In addition, two rate and multi-rate (injection) analysis methods are also used for unambiguous interpretation of the data. Both pressure-derivative and G-function analysis are used to analyze DFIT data in order to evaluate fracture-closure pressure. Other parameters obtained from ACA are instantaneous shut-in pressure (ISIP) and fracture efficiency. The log-log derivative plot confirms the presence of the late-time pseudo-radial flow regime. Pseudo-radial flow analysis by different methods are used to determine reservoir permeability and initial reservoir pressure.
Based on the analysis, it is inferred that reservoir is of good permeability as observed in high injection rates and corroborated by high permeability estimated from the radial-flow plot of ACA. The fracture breakdown pressures determined by conventional, two-rate and multi-rate analysis methods are supported by both modified-Hall and injectivity analysis. Fracture-closure pressure obtained from G-function, square-root, and derivative analyses compare favorably. Initial reservoir pressure and formation permeability estimated by different techniques are in good agreement, thus instilling confidence into the analysis.
The multiple techniques described here can be used for comprehensive and credible analysis of SRT as well as before-closure and after-closure analysis of falloff data in a disposal well
Innovative Reamer Stabiliser Technology Enhances Wellbore Stability and Creates Value by Reducing NPT, Improving Hole Quality, and Reducing Drilling Costs
Authors: Mehregan A. , Hassani V. , Brister R. , Rui X. 
Published: April 2024

Abstract
Value creation and cost reduction can be accomplished in many ways. Torque, drag, vibration, and Non-Productive time (NPT) all negatively impact total cost on drilling projects. Any efforts to create value by reducing these negative influences on a project’s metrics and overall cost are welcomed. Since most of those influences occur at the drill bit or BHA interface with the formation, that is one area where the focus on creating value and reducing cost occurs. Reamers, stabilizers, bits, gauge tools and hole opener tools are included in that technology focus area.
A new stabilizer reamer tool incorporating innovative technology has been introduced globally to address what existing conventional reamers and stabilizer reamers were failing to do with consistency across different formations. This tool’s primary focus is on wellbore stability and borehole quality. Additional benefits include controlling and reducing torque, drag, and vibration resulting in the biggest impact to reduction of NPT, days on well, casing point to casing point time, and consequently, total cost of a drilling project.
Ultimately, this paper details the design features and components of the new stabilizer reamer tool. Shaped TCI "donut" cutters, their patented placement structure, and fixed blade geometry, along with their design and placement work hand in hand to provide consistent positive metrics and increased value wherever applied. This paper also focuses on several tool applications around the world. Metrics were analysed and an optimized model of reamer placement in the BHA was generated. The case histories are presented where before/after data was analyzed, Lessons Learned registers were kept and moved from application to application, and subsequent design changes were proposed and incorporated.
The data show that managing torque, drag, and vibration while drilling using the new reamer tool, reduced the risk of stuck pipe, reduced trip times, increased borehole and caliper quality, and increased efficiencies for wireline, tubing, casing and liner, and completion runs. Consequently, the new reamer stabilizer tool definitively accomplished all value creation and NPT/cost reduction objectives in part due to the innovative cutter and blade shape, design, and placement.