bluuebunny/crossref_metadata_2025_split huggingface dataset:
4D Seismic Monitoring of a CO2-EOR Demonstration Project in a Desert Environment: Acquisition, Processing and Initial Results
Authors: Smith Robert , Bakulin Andrey , Jervis Mike , Hemyari Emad , Alramadhan Abdullah , Erickson Kevin 
Published: October 2018

Abstract
Saudi Aramco recently started the company's first CO2-EOR demonstration project in an onshore carbonate reservoir. Time-lapse (4D) seismic has proven to be a valuable reservoir management tool for monitoring the areal expansion of CO2 plumes in many similar projects around the world. However, the complex and dynamic nature of the near surface encountered in the desert environments of the Middle East results in high levels of 4D noise. This noise, coupled with the weak 4D signal expected from injection into a stiff carbonate reservoir, makes mapping the time lapse signal very challenging. The objective of this project was to develop a highly repeatable system capable of detecting small reservoir changes related to CO2 injection to enable the plume expansion to be tracked over time.
Achieving highly repeatable seismic data requires specialized seismic acquisition and dedicated processing. A novel acquisition system using buried receivers was adopted to reduce 4D noise resulting from near-surface variations. To minimize the non-repeatability inherent in using surface sources, a differential GPS guidance system was implemented to ensure high positioning accuracy. Even with these acquisition efforts, a fit-for-purpose 4D processing workflow was necessary to further reduce differences between surveys.
Despite the challenges faced, outstanding data repeatability has been achieved, with mean NRMS values of less than 5% for data acquired during the same season. This level of repeatability is comparable to data acquired in marine 4D surveys and has resulted in the detection of the small 4D signal caused by CO2 injection. Frequent monitor surveys, with one full survey acquired every four weeks, shows the CO2 plume growing over time with increasing injection volume. While the observed CO2 plume largely correlates to available engineering data, discrepancies have been identified when compared with the predicted seismic response based on the reservoir simulation model. This indicates that 4D seismic can be used to constrain the reservoir model, yielding a better history match and improved predictions to enable more informed engineering decisions to be made.
This is the first successful application of seismic monitoring of a carbonate reservoir in an area renowned for poor seismic data quality. To overcome the challenges, a novel hybrid acquisition system using buried sensors and surface sources was developed. Advances in the seismic processing workflow were also required to bring the 4D noise down to a level that enabled detection of the CO2 injection.
Ultra-low Interfacial Tension, Thermal Stability and Static Adsorption of Novel Viscoelastic Surfactant with Heavy Reservoir Oil
Authors: Janjua Aneeq Nasir , Sultan Abdullah S. , Kamal Muhammad Shahzad 
Published: October 2018

Abstract
Middle East reservoirs are usually characterized as high temperature and high salinity (HTHS). In chemical EOR, interfacial tension (IFT) is a key parameter that alters the reservoir environment. IFT measurements are challenging specially at high temperatures due to its dynamic nature. Viscoelastic surfactants are introduced because of their dual capability of lowering the IFT and improving the sweep efficiency of the reservoir. In this paper, the main objective is to determine ultralow IFT's and thermal stability that can be obtained from viscoelastic surfactants in the presence of heavy crude oil using spinning drop tensiometer (Kruss), thermogravimetric analyzer (TGA), nuclear magnetic resonance (NMR) and fourier transform infrared (FTIR) spectroscopy. Investigation of VES is performed with heavy reservoir oil (12cp at 90°C) and using high salinity formation brine (234,189 ppm). The solutions were prepared by the combination of viscoelastic surfactant and undiluted sea water and stirred until they attain equilibrium. Density and IFT at high temperatures are determined. Equilibrated solutions are used with heavy reservoir oil to determine the IFT reduction capability of viscoelastic surfactant at various concentrations from 0.1 to 1%. Results show a considerable reduction in IFT with viscoelastic surfactant up to 10−1 mNm−1 range. IFT reduction usually depends on the concentration of solutions used. Results also show that ultralow IFT was obtained at 50°C and 80°C. Encouraging results with TGA demonstrated that VES is thermally stable and show high resistance to temperatures up to 250°C. Long-term thermal stability up to 30 days at 90°C and 120°C temperatures was evaluated. 1H NMR show stability in structure while 13C NMR results show minor structural changes in the aliphatic region. FTIR results indicated good thermal stability with strong bonding between C-H and C=O. Static adsorption is evaluated by shaking the powdered core samples with VES at two different high temperatures for 24 hours. Concentration measurements are performed using total organic carbon (TOC) analysis. Static adsorption results give less adsorption when we have higher temperatures compared to lower temperatures. Experimental results indicate two major effects. Firstly, ultralow IFT obtained with the novel viscoelastic surfactant and it is thermal stable at high temperatures. Secondly, viscoelastic surfactant significantly reduces retention at high temperatures when compared with low temperatures. They are excellent additives in chemical EOR for HTHS conditions. They are also very useful when we have heavy reservoir oil and where IFT reduction is required to mobilize the oil and improve the sweep efficiency of the reservoir.
Customized Drilling Fluids Design to Drill Challenging Sections Using High-Performance Water-Based Mud
Authors: Pino Rafael M. , Elhabrouk Ihab , Addagalla Ajay , Jadhav Prakash B. 
Published: October 2018

Abstract
This paper presents a customized water-based drilling fluids design for drilling challengig sections through varying formations. The offset wells were reviewed to identify the issues while drilling the trajectory through troublesome reactive and depleted formations that showed wellbore stability issues, stuck pipe incidents, and induced severe losses.
Additional problems experienced while drilling include shale dispersion, resulting in fine solids buildup in the drilling fluid, and the adherence of shale to the drill pipe and bit, reducing penetration rates. The customized drilling and completions fluids system was designed for different intervals. The system was developed with the following objectives in mind: improved hole stability through reactive formations; enhanced hole-cleaning efficiency at critical angles; minimized risk of stuck pipe across depleted formations with high porosity and permeability; minimized or non-induced losses to formation utilizing a unique wellbore strengthening technique; and improved rate of penetration to optimize drilling efficiency.
This paper describes the customized high-performance water-based mud (HPWBM) design and performance. A comprehensive engineered approach addressed the challenges of drilling horizontal wells by using a high-performance aluminum complex and polyamine chemistry to improve wellbore stability.
This approach for drilling fluid chemistry provides an alternative replacement for previously used nonaqueous drilling fluids. Three wells were drilled successfully, and the lessons learned on these wells were incorporated in drilling subsequent wells to continue improving drilling performance.
Collaborative Design of a Bottomhole Assembly Improves Performance and Provides a Cost-Effective Solution in a Massive Extended-Reach Drill Project
Authors: Bin-Madhi Adel , Azher Mohammed Mushtaq , Ghazzawi Ayman , Al-Mutairi Yousef , Balka Muhammad Sarfraz , Al Hajri Huzam , Harbi Magbel 
Published: October 2018

Abstract
During the field-development life of a mature extended-reach drill (ERD) project, a wide range of drilling tools and practices were introduced to continuously improve drilling performance and well delivery times.
One of the main challenges encountered in the ERD wells was in the 12¼-in. curve section, and drilling through interbedded hard layers with severe downhole stick/slip and downhole vibrations. Historically, both motor and motorized rotary steerable system (MRSS) bottomhole assemblies (BHAs) were used to drill this section. However, the motor BHA's lower rate of penetration (ROP) and weight transfer problem cause it to be an economically inefficient strategy in contrast with the MRSS BHA, successfully drilled through all of the challenges with higher ROP and a relatively lower overall cost.
Driven by cost reduction necessity, an intensive engineering effort was implemented by the operator and service provider drilling engineering teams to change the motor BHA into a cost-effective drilling strategy for the challenging 12¼-in section.
Analyzing the design and performance of all previous motor BHAs led to identifying the main challenges. Detailed modeling was then performed, involving well trajectory design, BHA design optimization, hydraulics modeling, and torque and drag modeling. The modeling included static simulation as well as drillstring vibrations using finite element analysis (FEA) dynamic simulation. This extended engineering analysis improved the bit and BHA selection capability. Several drill bits and BHA options were modeled and simulated under different drilling conditions to determine the most stable configuration. Simultaneously through the dynamics simulation, a stable drilling parameters plan was generated to improve the drilling performance.
The modeling results indicated that the lighter BHA configuration minimized BHA - formation contact area, allowing for smoother and efficient weight transfer downhole. A reduction in BHA vibration produced a step improvement in ROP and drilling performance.
The engineering modeling results were implemented by replacing the previously used motor BHA drill collars with heavy-weight drillpipe and smaller size jars. This hardware change resulted in an unprecedented cost reduction, a 52% improvement over the previous motor BHA in delivering the challenging section, achieving multiple additional records, and 56% ROP improvement over the field. This paper will present the design process and the detailed results for each run. Recommendations will be provided on how this process can be applied to increase ROP performance and reduce the cost per foot for such drilling applications.
Effect of In-Situ Generation of Heat and Pressure on Phase Behavior of Gas Condensate
Authors: Hassan Amjed M. , Mahmoud Mohamed A. , Al-Majed Abdulaziz E. , Elkatatny Salaheldin M. , Al-Nakhli Ayman R. , Bataweel Mohammed A. 
Published: October 2018

Abstract
Condensate blockage reduces the gas deliverability from gas condensate reservoirs, when the reservoir pressure drops below the dew point pressure. Several techniques are commonly used to avoid condensate banking, by maintaining higher reservoir pressure. However, these methods required large investment and resulted in temporary improvement in the gas production. In this paper, the effect of heat and pressure generated by using a novel technique (thermochemical reaction) will be investigated on the phase behavior of an actual gas condensate reservoir.
Several treatments were discussed in this paper to evaluate their effectiveness in removing the liquid banking and improving the gas production. Then, the effect of chemical treatment on altering the phase behavior for condensate reservoir was studied. To simulate the actual operations of condensate treatment; actual reservoir fluids were used. Peng-Robinson equation of state (EOS) was used to develop the EOS-model, employing WinProp from CMG suite, based on available data from the studied reservoir. Flash calculations were conducted at surface conditions, and the phase properties were studied as a function of pressure and temperature.
Moreover, managing hydrocarbon dew point can reduce the condensate process, i.e. the dew point can be adjusted in such a way that prevents the hydrocarbon condensation. Chemical treatments might be used to reduce the dew point and improve the condensate removal process. In addition to that, hydrocarbon condensation might form if the formation temperature become less than the dew point temperature. Therefore, condensation can be prevented by increasing the temperature to keep it above the dew point temperature. In situ heat generation technology is used as a new technique of maximizing the heat penetration and improve recovery efficiency of gas condensate at lower cost compared to the current practices.
Synthesis and Experimental Investigation of Novel CNT-Polymer Nanocomposite to Enhance Borehole Stability at High Temperature Drilling Applications
Authors: Ahmad Hafiz Mudaser , Kamal Muhammad Shahzad , Al-Harthi Mamdouh A. , Elkatatny Salaheldin Mahmoud , Murtaza Muhammad Mobeen 
Published: October 2018

Abstract
The successful drilling operation of oil and gas wells required high quality of drilling fluids which can stabilize well formations and able to withstand deep wellbore conditions of elevated temperature. Wellbore formations are mainly composed of shale (soft clay) and are likely to destabilize upon interacting with water. The instability of wellbore is caused by the interactions of water with the formation that results in the swelling of shale. Specialized drilling fluids can overcome this issue by stabilizing wellbore formations.
The purpose of this study is to develop a novel CNT-polymer nanocomposite through in situ polymerization process and to enhance rheological properties, borehole stability and filtration characteristics for high-temperature and high-pressure drilling applications. The thermal stability of nanocomposite was assessed using TGA analysis. The nanocomposite concentration (2 w/v.%) was employed with the base drilling fluid to study the impact on rheological properties at elevated temperature from 100°F to 300°F and 300 psi pressure. The results showed that rheological properties (viscosity, yield point, gel strength) were stable up to 300°F with (2 w/v.%) concentration of nanocomposite. The HTHP filtration experiment showed that fluid loss of modified drilling fluid significantly reduced compared to the base drilling fluid. Shale dispersion experiments were carried out at (100°F, 200°F, 300°F) for a shale sample obtained from the actual drilling field of Saudi Arabia. The XRD analysis of shale sample showed 19% clay contents in the shale sample. The shale recovery performance indicated that using 2 w/v.% concentration of nanocomposite in the base drilling (modified drilling fluid) has significantly reduced the dispersion of shale (up to 90%) compared to the base drilling fluid. The linear shale swelling experiments were carried out using nanocomposite modified drilling fluid and it was observed that use of nanocomposite appreciably reduced the swelling of shale compared to the base drilling fluid.
The use of polymer nanocomposite as water-based drilling fluid additive enhances the rheological properties, filtration characteristics and borehole stability at high-temperature drilling applications.
Temperature Impact on Adsorption Contribution to Sequestration of CO2 in Immature Shale Formations in Saudi Arabia
Authors: Eliebid Mohammed , Mahmoud Mohamed , Al-Shehri Dhafer , Elkatatny Salaheldin , Abouelresh Mohamed , Shawabkeh Reyad 
Published: October 2018

Abstract
The environmental concerns to reduce carbon dioxide emissions have led to huge advancements in carbon capture and sequestration in different geological formations in the past two decades. Due to the high abundance of shale basins around the world, in recent years, CO2 sequestration potential in these formations has become an attractive option. However, most of the shale formations are considered immature to become shale oil or shale gas. These types of shale usually contain high organic matter (kerogen) generally expressed as total organic carbon (TOC) compared to mature shale reservoirs. The poor petrophysical properties of shale rocks in terms of porosity and permeability the adsorption capacity became a very significant factor that controls the amount of CO2 these formations can store. Previous experimental studies showed that high TOC indicates high adsorption capacity. Here adsorption of CO2, CH4 and 10%CO2/90%CH4, adsorption isotherms and adsorption thermodynamics were studied on intact three shales SH1, SH2 (immature) and SH3 (mature) from Qusaiba field in Southern Saudi Arabia at 50, 100 and 150°C. We attested that as CO2 amount increased, the adsorption capacity of the three shales increased accordingly justifying the good potential for using CO2 for enhanced improved methane recovery. Furthermore, the three shales exhibited diverse responses to the studied temperatures. SH1 and SH3 showed an endothermic trend from 50 to 100°C with a huge increase in the adsorption followed by an exothermic significant decline at 150°C. SH2 had no CH4 adsorption at 50°C and exhibited endothermic adsorption behavior; increasing the adsorption at elevated temperatures. These variations in adsorption comportment resulted from thermally induced alterations in the clay minerals crystallinity confirmed by x-ray diffraction at 50 and 150°C. Thermodynamics analysis of Gibbs free energy, adsorption enthalpy and entropy concluded that all three shales has high affinity to CO2 and lower adsorption enthalpy and entropy compared to CH4. That because of the strong electrostatic attraction between partially negative CO2 molecules and shale clay minerals positive surface cations. Contrary to many studies in the literature, adsorption isotherms fitting demonstrated that adsorption of CO2, CH4 and 10%CO2/90%CH4 on the three shales is multi-layered and best modeled by Freundlich and BET isotherms rather than Langmuir mono- layer isotherm.
CO2-Foam Rheology: Effect of Surfactant Concentration, Shear Rate and Injection Quality
Authors: AlYousif Zuhair , Kokal Sunil , Alabdulwahab Amin , Gizzatov Ayrat 
Published: October 2018

Abstract
Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and sequester CO2 underground. While CO2 injection has been successful, a major challenge facing this technique is enhancing volumetric sweep efficiency. Some of the factors that contribute to this challenge are the low density and viscosity of injected gas relative to reservoir fluids. The use of foam is one of the most promising techniques to increase the CO2 apparent viscosity, thereby improving volumetric sweep efficiency.
Increasing the CO2 viscosity by using surfactants has the potential to mitigate some of the challenges associated with CO2 injection projects. The objective of this work is to investigate the effect of various surfactants on CO2-foam viscosity. Four surfactants were used to evaluate the foam generation and rheological properties of CO2-foams at high pressure and temperature. Dynamic foam viscosity measurements were conducted in a special foam rheology apparatus with supercritical (sc-CO2) under high pressure (3200 psi), temperature (210°F) and salinity conditions. The foam was generated by injecting sc-CO2 and surfactant at different concentrations (0.20, 0.50 and 1.00 wt %), shear rates (10-600 s-1) and qualities (70, 85 and 90%).
The results indicate that all surfactants were able to generate good quality foam at high pressure and temperature. The foam viscosity increases with surfactant concentration. All foams exhibited shear thinning behavior, with foam viscosity decreasing with increasing shear rates. In general, the highest viscosity for each surfactant was reported at the lowest shear rates. The results also showed that the foam quality has an impact on foam viscosity for some cases. The highest foam viscosities for surfactant 2 were achieved at 85% quality. However, the quality had no significant impact on foam viscosity for surfactant 3.
Image Reconstruction of Multiphase Flow Metering: A Compressed Sensing Approach
Authors: Al-Shuhail Shamael A. , Noui-Mehidi Mohamed N. 
Published: October 2018

Abstract
Multiphase flow measurements, based on tomographic imaging techniques, have made substantial progress in the past several years. In particular, ultrasonic tomographic reconstruction has shown its high potential in accurately measuring fluid fractions in a flow cross-section based on direct flow measurements. These types of measurements are very attractive as the system is nonradioactive, has direct contact to fluid, yet without flow obstruction. An ultrasonic tomographic multiphase flow meter (UTM) is being developed to capture the fluid flow rates and phase compositions in producing oil wells. The UTM aims to generate cross-sectional images of the flow inside the pipe. To recover these images, complex computations and high processing time are required, based on a limited amount of available data. For this purpose, compressive sensing (CS) reconstruction methods have shown great potential in overcoming the mentioned data quality and quantity issues. CS builds upon the fact that one can recover certain data of interest from potentially very few measurements. Many CS algorithms have been proposed in the literature. In this paper, we seek to find a suitable algorithm by comparing different CS algorithms in terms of the resulting recovered image quality. Specifically, we survey three algorithms in CS, namely basis pursuit, iterative soft thresholding (IST), and orthogonal matching pursuit (OMP). We also compare the results of the CS algorithms to that of a least-square based conventional algorithm. The numerical results show the superiority of CS recovery algorithms over the conventional approach, both qualitatively and quantitatively. The results also suggest that high image quality could potentially be achieved with less complex CS algorithms, i.e., the IST and OMP algorithms. As presented in the paper, our goal is to adapt CS reconstruction algorithms for images generated by the UTM, for the purpose of accurate quantification of oil, gas, and water phase fractions produced from different wells.