bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Amott Tests Help Quantify Primary Driving Forces in Spontaneous Imbibition in Water-Wet and Oil-Wet Limestone Rock
Authors: Kaprielova Ksenia , Yutkin Maxim , Gmira Ahmed , Ayirala Subhash , Yousef Ali , Radke Clayton , Patzek Tadeusz 
Published: March 2023

Abstract
The improved oil recovery techniques, such as customized ionic composition waterflood or "smart-water" flood, are being developed to increment crude oil production. Counter-current spontaneous imbibition of brine into oil-saturated rock is a critical mechanism of recovery of the crude oil bypassed in highly-heterogeneous carbonate rocks. In laboratory, spontaneous imbibition in the Amott cell experiment is the main instrument to explore oil recovery from oil-saturated core plugs at different wettability conditions. The classical Amott test, however, masks a number of flaws that hinder interpretation of the physical phenomena in recovery dynamics and precise modeling of the cumulative recovery profiles. In this work, we identify these flaws in the spontaneous imbibition experiments with mixed-wet limestone samples saturated with crude oil. We describe an improved Amott method and study crude oil recovery from mixed-wet carbonate core plugs. The introduced modifications of the Amott test ensure reliable and reproducible results for both non-wetting mineral and crude oils. Finally, we show that the resulted smooth recovery profiles of oil production can be described with a mathematical model with high accuracy. For the first time, we show that generalized extreme value (GEV) distribution can be applied to model cumulative oil production from mixed-wet carbonate core samples.
Counting the Effect of Crude Oils: Towards Increasing the Efficiency of Carbonate Matrix Acidizing
Authors: Al Hamad Mohammed , Abbad MustaphaFarhan , Ali Farhan , AlOtaibi Nader , AlRadhwan Azizah , AlQuisom Mohammed , Abdallah Wael 
Published: March 2023

Abstract
Carbonate matrix acidizing creates wormholes in the damaged formation around the wellbore and is used extensively to enhance well productivity. There are many factors discussed in literature that can positively or negatively affect the efficiency of carbonate matrix acidizing, such as mineralogy, permeability, porosity, and factors associated with the rock matrix and the acidizing fluids. However, the influence of reservoir crude oil on the acidizing operation has not been addressed and is the subject of this study.
Several limestone outcrop samples were selected and used in this study after evaluation of their petrophysical properties. The samples were fully saturated with deionized water; some samples were centrifuged and aged at high-pressure/high-temperature (HP/HT) conditions with different grades of crude oils. Linear acidizing experiments were executed; the preliminary acidizing tests showed optimal flow rate of 2 cm3/min. A baseline test was then conducted, using preflush fluid injection prior to acidizing to represent the real scenario of a stimulation job in the reservoir. The preflush helped to clean out the rock matrix, preparing the sample for acid injection. Lower pore volume before breakthrough (PVBT) was observed compared to the preliminary tests without the preflush. Then, linear acidizing tests were run on oil-saturated core samples. The results showed that the lower crude oil API is, the less acid volume needed to achieve acid breakthrough. This is mainly due to the viscous fingering that occurs because of the high viscosity contrast between the low-API crude oil and the 15% HCl acid used.
These results show the impact of crude oils with different API on the acidizing efficiency, which is very important information for reservoir engineers and should help proper planning the potential volume of acid needed and in making the right operational decisions for better financial impact.
Gas Tracer Technology to Improve Reservoir Understanding and Evaluate EOR Strategy, a Pilot Study in Kuwait
Authors: Al-Mayyan Haya , Pradhan Akshaya , Ziyab Khaled , Wurtz Marie , Huseby Olaf , Nurafza Peyman , Faulkner Tom 
Published: March 2023

Abstract
This paper describes planning, implementation, and results of chemical gas tracers used in a gas injection pilot study in a heterogeneous multilayer reservoir, onshore Kuwait. The use of tracer for waterflooding is a common practice to understand and improve field performances. In contrast, tracing injected gas with chemical tracers is applied less frequently. This study presents the first implementation of gas tracers in a pilot study in Kuwait and is an early adaptation of tracers to investigate gas-based EOR in the Middle East. The pilot comprises of one injector completed in three target layers and seven producers, completed in similar or other different layers. Unique gas tracers were injected into isolated layers independently at different times to evaluate the injector-producer connectivity in each layer. The producers and re-injected gas were sampled for one year to evaluate gas tracers return. The recovered tracer masses were evaluated against the injected amount to provide information on connectivity and sweep efficiency. The main revelation from the gas tracer study is their distinct difference from what could be expected from a consideration of the water flow itself. A likely explanation for the difference is that the water and gas behave differently in the reservoir, which in turn leads a conclusion that gas enhances the production of oil by replacing oil in the reservoir volumes.
CO2 Foamed Fracturing Fluids for High Temperature Hydraulic Fracturing
Authors: Karadkar Prasad , Harbi Bader , Malik Ataur , Alsakkaf Mohammed , Khan Safyan 
Published: March 2023

Abstract
CO2-foamed fracturing fluids injection can assist water conservation during hydraulic fracturing. Moreover, foamed fracturing fluids offer a desirable alternative over conventional fracturing fluids, particularly in stimulating water-sensitive formations, the need for shortened flowback time, and energizing created fracture geometry. The thermal stability of foam at high temperatures is one of the main challenges. In this paper, CO2-foamed acrylamide-based terpolymer based fracturing fluid was developed for high temperature application.
The foam viscosity development depends on the gas, foam quality, the viscosity of the external phase, foaming agent and foam stabilizers. Rheological properties of N2 and CO2 foams containing acrylamide-based terpolymer were measured at high temperatures i.e. 300 to 350°F and shear rate from 100 to 500 1/s. A circulating flow loop foam rheometer was used to measure the rheological behavior of foamed fluid prepared using linear gel. Foam stability improvement using nanoparticles was also demonstrated.
The viscous character of the external phase of the foam plays a considerable role in the viscosity of foam. In this paper, water and linear gel prepared using 35 ppt acrylamide-based terpolymer has been studied at 75% foam quality and two different temperatures. A 75% quality foam viscosity having water as the external phase gave 70 cp with N2and 31 cp with CO2 at 100 1/s, whereas viscus linear gel gave 146 cp with N2 and 64 cp with CO2 at 100 1/s studied at 300°F. After increasing the test temperature to 350°F, there was a significant drop in viscosity noticed. The thermal stability of foam can be enhanced by the synergetic effect of surfactant and nanoparticles. The foam half-life was delayed from 5.5 min to 9.1 min after the addition of silica nanoparticles using water as base fluid.
Viscous properties of the fracturing fluids influence the fracture geometry and capability of transporting proppant into the fracture. Based on available literature reports, the rheological properties of foamed fracturing fluids limit to 300°F. This paper reveals the rheological properties of CO2-foamed fracturing fluids in a temperature range of 300 to 350°F and therefore helps to design fracturing treatment to stimulate reservoirs with high temperatures.
Addressing Hydraulic Fracturing Performance Challenges in HPHT Well with New Fluid System and Comprehensive Fracturing Study Utilizing Full 3D Simulator
Authors: Nurlybayev Nurlan , Al-Jalal Ziad , Samuel Mathew , Farouk Mohammad , Ghazwi Mustafa , Yaseen Ali , Muhammad Raja Jalil 
Published: March 2023

Abstract
For achieving successful stimulation treatment in HPHT environment, a robust and state-of-the-art fluid technology together with the use of a versatile simulation design tool is crucial. The scope of this paper is to present case histories on the fracturing design, application and evaluation and its results in HTPT wells in Saudi Arabia. Additionally, a comparative analysis and recommendations will be presented to identify the optimum hydraulic fracturing treatment design for HPHT applications.
Extensive laboratory research was performed to develop and optimize a robust fracturing fluid that can be used for HT application in low permeability wells in Saudi Arabia, in the design phase of the program. Several chemically modified polymer fluid systems were developed, and their stability at high temperature, proppant suspension, and regained permeability were determined. Test phase was considered as a very critical stage to meet the project targets, as in either case indigent fluid rheology leads to ineffective stimulation treatments, especially in applications above 300 deg F. Upon completing the laboratory tests, the fracturing design was considered to apply full 3D software for achieving a comprehensive simulation of fracture model.
The laboratory research and development allowed the development of a new high temperature fracturing fluid that met the requirements, and provided stability for the required pumping time, to deliver low formation damage, manageable gel breaking time, excellent fracturing fluid leak-off control and sufficient proppant transport capabilities. Validation of fracturing fluid for field implementation was not enough, as sufficient fracturing design had to be in place, thus full 3D modelling software was used, utilizing essential well and formation information and detailed parameters of the new fluid system. A comprehensive study has been done during new fracturing fluid development phase, and additionally a comparison of pseudo 3D and full 3D software models for different scenarios were performed to optimize the fracture treatment design.
The paper will present precise solutions to perform fracturing treatment in HPHT formations and will be a guide for designing the treatment fluid system, fracture modelling and well treatment execution. Additionally, the advantages of using full 3D software for fracturing simulations and its correlation with field production results will be highlighted.
Reviving Production From Over 100 Deep Gas Wells Suffering From Halite Deposition In Oman Thru Velocity String
Authors: Al Rashdi Ahmed , Ghaempanah Babak , Al Hijri Amira , Koot Wouter , Bolourinejad Panteha , Al Daraai Thabit , Al Battashi Ibrahim , Awan Kamran 
Published: March 2023

Abstract
Following the reduction of system pressure through depletion compression more than 150 deep gas wells started struggling from halite deposition. Halite deposition in the completion restricted or blocked the production from the lower reservoir in these wells and reduced the total gas production of the field by about 40%. Meanwhile, many of the wells with halite deposition issue were also suffering from liquid loading and velocity strings were isntalled in them as the primary means of gas well deliquification. Many of these wells with velocity string showed no further halite deposition due to increase of the bottom hole pressure and reduction of the draw-down. Consequently, frequent freshwater bull heading or clean out with coiled tubing were no longer needed. This observation triggered the idea to create synergy between gas well deliquification and halite management through installation of velocty string. This synergy does not exist in every case, and this paper elaborates on identifying where it exists.
An Overview of Advanced Subsurface and Surface Measurements for CCUS Project
Authors: Al-Zayani Alia I , Patil Pramod D. , Al-Qasim Abdulaziz S. , Kokal Sunil L. 
Published: March 2023

Abstract
Monitoring and surveillance (M&S) is one of the key requisites for assessing the effectiveness and success of any CCS/CCUS projects. It will help understand, track, monitor, and predict the Injectant plume migration, flow paths, and breakthrough times. The M&S helps in quantifying sequestered injected gas and any inadvertent leakage. It provides a good understanding of the remaining oil saturation (ROS) and its distribution in the reservoir.
A comprehensive and advanced monitoring and surveillance (M&S) program was developed and is currently being deployed to address CCS/CCUS project objectives. The advanced M&S plan incorporates conventional, advanced, and emerging novel technologies for wellbore and inter-well measurements. These include advanced time-lapse pulsed neutron, resistivity, diffusion logs, and bore-hole gravity measurements, cross-well geophysical measurements, water and gas tracers, geochemical, compositional and soil gas analyses, and 4D seismic and surface gravity measurements.
Results from monitoring and surveillance technologies provide a better understanding of the reservoir dynamics within the subject area. The results can be used to refine the reservoir simulation model and fine tune its parameters. This paper reviews some proven best practices and draws examples from ongoing projects and related novel technologies being deployed. It will then look at the new horizon for M&S technologies for CCS and CCUS.
Rigless Mineralogy Logging- A Reality for Improved Evaluation of Complex Formations
Authors: Van Steene Marie , Ma Shouxiang , Ghadiry Sherif 
Published: March 2023

Abstract
A new slim pulsed neutron (nPN) logging technology has recently been introduced in the industry. Although the technology's main deliverables aim at reservoir saturation monitoring, the technology has seen substantial improvements in quantitative mineralogy logging. It is now capable of providing mineralogy data quality on par with openhole measurements, thus filling the gap where mineralogy data are required but not acquired during openhole logging. The main objective of this paper is to assess this nPN technology for formation mineralogy, with discussions of advantages, sensitivities, uncertainties, and limitations. Best practices in obtaining high-quality mineralogy data with this technology in open hole or cased hole wells, riglessly, are also recommended.
The primary application of pulsed neutron (PN) logs is for reservoir saturation monitoring, be it with time-domain capture data (sigma) or with energy-domain spectral data (carbon-oxygen). With the current slim PN technology, mineralogy derived from the capture spectroscopy (featuring direct measurement of the main elements of silicon Si, calcium Ca, sulfur S, iron Fe, and gadolinium Ga) has always been the last resort and has been used only if no other lithology information is available, because it suffers from low precision and the difficulty to evaluate elements like magnesium Mg in carbonate reservoirs.
With the new nPN, the quality of the mineralogy log has improved dramatically, making it equivalent to the mineralogy obtained with openhole logging. It benefits from the latest technological advancements, including high output minitron source, fast electronics, and new detector material with high spectral resolution. Methodologically, it combines information from both capture and inelastic spectroscopy to deliver more precisely the elements of Si, Ca, S, Fe, Gd and magnesium Mg, aluminum Al, titanium Ti, and potassium K. The combination of capture and inelastic spectroscopy confers an advantage in increasing the sensitivity to magnesium, which allows separating calcite from dolomite.
Results show that the rigless nPN mineralogy data quality is close to the latest and most advanced openhole spectral mineralogy log quality, complementing the lithology logs interpreted from traditional openhole logs. It allows for a more precise evaluation of the mineralogy in complex evaluation situations, where mineralogy data are required but were not acquired during openhole logging, such as those wells drilled before elemental mineralogy logs were available just two decades ago. As with any other technologies, nPN has limitations. Proper job planning, recommended in this study, is the key to ensure data quality.
New nPN provides an opportunity to gather reservoir mineralogy data in any wells, including rigless, in small holes, and through small restrictions, thereby filling the gap where mineralogy data is required, but not acquired during primary openhole logging.
Innovative Solid Lubricant Solution to Reduce Friction in Challenging ERD wells
Authors: Olivares Tulio , Turi Zach , Hayes Brandon 
Published: March 2023

Abstract
Extended reach drilling (ERD) has become increasingly more frequent in the petroleum industry as it allows access to additional reserves in oil and gas reservoirs from a single wellbore. Consequently, this has led to an increase in friction related problems while drilling and running casing. This paper describes the extensive lab testing and technical implementation of an innovative technology that utilizes a customized solid lubricant to reduce friction and help operators achieve challenging depths.
Comprehensive lab testing was conducted to tailor the required formulations of the solid lubricant and two field trials were completed to evaluate the performance. To properly conduct this evaluation, key performance indicators were established in both wells. A minimum torque reduction value of 10% was targeted for a treatment containing 5 pounds per barrel (ppb) of the solid lubricant. Baseline torque values were captured prior to the lubricant addition and were the benchmark for performance evaluation. Drilling fluid from the active pit was then enhanced with 5-ppb of the solid lubricant and sweeps were pumped downhole to reduce friction.
Two extended reach wells were identified in which water-based mud was used to drill. On Well A, at 79-degree inclination high and erratic torque was experienced which affected the drilling performance. Baseline torque was recorded and a sweep with 4 ppb of the solid lubricant was pumped: resulting in a 5.5% torque reduction. After drilling another stand, a second sweep was pumped with 5 ppb concentration and torque was reduced 14.7%. On Well B, at 84-degree inclination high and erratic torque was once again experienced. Baseline torque was recorded, and the first sweep was pumped with 5 ppb of the solid lubricant: resulting in a 10.4 % torque reduction. A second sweep was immediately pumped with another 5 ppb concentration and torque was reduced by 24.3%. In both Well A and Well B, a pill was spotted in the open hole with 8 ppb solid lubricant concentration to assist with the liner run. These field applications successfully demonstrated the concept of this innovative technology to reduce friction and overcome torque challenges in ERD applications; thus, resulting in a drastic reduction in nonproductive time.
The industry is continuously looking for opportunities to reduce non-productive time while drilling. This innovative solid lubricant is environmentally safe, compatible in all mud systems, and is highly effective in low concentrations to reduce friction while drilling in some of the most challenging extended reach wells. Minimizing friction and the subsequent torque issues will allow for optimal rates of penetration while drilling in these challenging conditions and thus reduce the overall time constructing the well.
Ranking of Geologic and Dynamic Model Uncertainties for Carbon Dioxide Storage in Saline Aquifers
Authors: Ates Harun , Gupta Anuj , Chandrasekar Vikram , Vaidya Ravimadhav , AlMajid Muhammad , Yousif Zuhair 
Published: March 2023

Abstract
Growing concerns over global climate change is also increasing the interest in developing technologies to reduce the concentration of carbon dioxide (CO2) in the atmosphere. Geological Carbon Sequestration which injects CO2 into subsurface formations such as deep saline aquifers, depleted hydrocarbon reservoirs are some of the viable options to reduce CO2 emissions into the atmosphere. Deep saline aquifers are a particularly good choice due to their wide geographical distribution and proximity to emission sources that provide easy accessibility and storability of CO2.
Saline aquifers, however, are data-poor systems that requires a thorough understanding of the impact of all factors and their uncertainties on long-term CO2 storage for risk assessment. This study considers a wide range of geologic and dynamic model uncertainties, including structural uncertainties, petrophysical heterogeneities, dynamic flow parameters and geochemical reactions to define the most critical parameters for different CO2 trapping mechanisms. Experimental design over stochastic modelling and sampling is used to minimize the computational cost of the study.
A commercially available, compositional reservoir simulator with reactive transport modeling capability has been used in this study to account for the impact of potential geochemical reactions. Assumed reactive transport model considers the water solubility, ionization, and mineral trapping mechanisms of CO2 in saline reservoirs for a range of components of dissolved salts in the brine as well as the pH of the brine. Chemical reactions that may occur with the rock minerals (Kaolinite, Anorthite and Calcite) when adding the CO2 are prescribed as input into the simulator. Simulations also include effects of hysteresis and diffusion processes.
Study shows that the most important parameter for all trapping mechanisms is the permeability since it controls the injection capacity. Beyond that, different combination of parameters with different range of uncertainties alter the ranking of factors influencing dissolution, ionization, hysteresis, mineralization and the movement of CO2 within the aquifer. There is no unique set of parameters that maximizes all storage mechanisms. There is a significant overlap and change in amount the amount of CO2 stored via different mechanisms depending on the parameter combinations. Study results also provide insights into how one can prioritize data gathering needs depending on the objectives, data uncertainties and their sensitivities for an aquifer site under consideration.
NGL Process Optimization at Khurais Producing Facility to Maximize NGL Recovery and Minimize H2S Content through HYSYS Simulations
Authors: Bajuaifer Hatem A. , Khan Ashiff , Hawsawi Ahmad M. , Amminudin Kamarul A. 
Published: March 2023

Abstract
This paper covers an optimization study at Aramco's Khurais processing facility to maximize NGL yield and minimize H2S content through HYSYS simulation. Model validation and identifying the confidence level of the model (prior optimization) approach and results are covered along with the realized results of the optimized operating envelope in simulation compared to field trial results.
The optimization approach focused on flashing more light ends due to a pressure drop in both the condensate feed drum and condensate stripper column while reducing NGL heating to maximize C3+ yield while maintain H2S below 30 PPMv. The identified optimized operating enveloped was implemented and benefits were realized.
The main conclusions and realized benefits of adjusting the operating parameters to the optimized operating envelope includes maximizing NGL recovery in the facility by more than 900 BPD while maintaining quality parameters within limits, reduced the steam consumption by more than 150,000 lb/day and creating more tolerance to process upsets and normal fluctuations.
The novelty of this paper is that it describes a process to define the confidence level of the model prior to commencing the optimization on a pre-existing model. In addition, it highlighted a simple approach to maximize C3+ recovery while minimizing H2S content and energy consumption, which creates room for optimization opportunities in any gas plant with no gas sweeting system.