This page has only limited features, please log in for full access.

Unclaimed
Saad Alafnan
King Fahd University of Petroleum & Minerals, Saudi Arabia

Basic Info

Basic Info is private.

Honors and Awards

The user has no records in this section


Career Timeline

The user has no records in this section.


Short Biography

The user biography is not available.
Following
Followers
Co Authors
The list of users this user is following is empty.
Following: 0 users

Feed

Review article
Published: 30 June 2021 in Journal of Petroleum Science and Engineering
Reads 0
Downloads 0

Accurate hydrocarbon reserve estimation is a crucial step for successful field development. Unlike for conventional reservoirs, however, reserve estimation for unconventional reservoirs is challenging due to the multiscale transport and multiphysics storage mechanisms involved. In this paper, we investigate the applicability and the limitations of Langmuir adsorption isotherm for the major unconventional gas resources, namely, shale-gas and coalbed methane (CBM) reservoirs, respectively. In general, reserve estimation methods for both shale-gas and CBM rely on Langmuir isotherm to model the sorbed gas capacity. Thus, we provide a detailed discussion on the characteristics of unconventional reserves and elucidate the applicability of the Langmuir model for estimating gas storage volumes. To add to the discourse on storage capacity modeling, molecular simulation studies of organic materials (kerogen) with various degree of heterogeneity were conducted. The adsorption behavior of multicomponent mixtures was also investigated. Simulations suggest that increased heterogeneity of the organic constituents and the presence of more than one component curtail the predictive power of the Langmuir framework. Furthermore, we observed that kerogen storage capacity is not only governed by its chemical composition but also by the particular kerogen type. Observed discrepancies with respect to reserve estimates for different evaluation models hint at a lack of understanding the underlying dynamics of unconventional reservoir gas storage phenomena.

ACS Style

Saad Alafnan; Abeeb Awotunde; Guenther Glatz; Stephen Adjei; Ibrahim Alrumaih; Ahmed Gowida. Langmuir adsorption isotherm in unconventional resources: Applicability and limitations. Journal of Petroleum Science and Engineering 2021, 207, 109172 .

AMA Style

Saad Alafnan, Abeeb Awotunde, Guenther Glatz, Stephen Adjei, Ibrahim Alrumaih, Ahmed Gowida. Langmuir adsorption isotherm in unconventional resources: Applicability and limitations. Journal of Petroleum Science and Engineering. 2021; 207 ():109172.

Chicago/Turabian Style

Saad Alafnan; Abeeb Awotunde; Guenther Glatz; Stephen Adjei; Ibrahim Alrumaih; Ahmed Gowida. 2021. "Langmuir adsorption isotherm in unconventional resources: Applicability and limitations." Journal of Petroleum Science and Engineering 207, no. : 109172.

Journal article
Published: 19 June 2021 in Fuel
Reads 0
Downloads 0

Diffusion tortuosity is an important microstructural parameter for computing effective gas transport coefficients in porous media. In this study, a realistic kerogen structure was built to quantitatively establish a clear understanding of the adsorption impact on diffusion tortuosity in the organic materials of shale. A molecular simulation study was employed to reconstruct a Type II-D kerogen model on a computational platform. A structure of five kerogen macromolecules was obtained through a series of NVT – NPT ensembles. There was a thorough characterization of the porosity and pore size distribution of the final structure. A grand canonical Monte Carlo method was used to compute the adsorption of methane for a pressure range up to 40 MPa. Freundlich and Langmuir models were employed to further parameterize the adsorption capacity. A molecular dynamics diffusion study was performed on the kerogen-adsorbed molecule configurations to obtain the effective diffusion, which was then used to estimate the tortuosity. Methane molecules follow tortuous pathways of diffusion, imposed by the heterogeneity and confinement of kerogen. The tortuosity is further impacted by the adsorption effect. Kerogen-methane interactions increase this tortuosity by a factor as high as 3.6 compared to an adsorption-corrected tortuosity.

ACS Style

Clement Afagwu; Saad Al-Afnan; Shirish Patil; Jaber Aljaberi; Mohamed A. Mahmoud; Jun Li. The impact of pore structure and adsorption behavior on kerogen tortuosity. Fuel 2021, 303, 121261 .

AMA Style

Clement Afagwu, Saad Al-Afnan, Shirish Patil, Jaber Aljaberi, Mohamed A. Mahmoud, Jun Li. The impact of pore structure and adsorption behavior on kerogen tortuosity. Fuel. 2021; 303 ():121261.

Chicago/Turabian Style

Clement Afagwu; Saad Al-Afnan; Shirish Patil; Jaber Aljaberi; Mohamed A. Mahmoud; Jun Li. 2021. "The impact of pore structure and adsorption behavior on kerogen tortuosity." Fuel 303, no. : 121261.

Journal article
Published: 09 June 2021 in Energy Reports
Reads 0
Downloads 0

Gas transport in ultra-tight rock is non-Darcian. In addition to continuum flow, there are multiple other flow mechanisms such as slip flow and pore and surface diffusion. Various multi-physics models have been put forth in the literature to forecast the apparent permeability of gas in shales and ultra-tight formations. However, a means of accurately describing the relative contributions of physics in multiscale pore systems remains a challenge. Moreover, it is important to explain pore size, pressure dependency, and the relationships among adsorption, diffusion, and permeability in porous media. For these reasons, a semi-analytical model is proposed to predict gas permeability according to the viscous flux, pore diffusion and surface diffusion and establish control of the adsorbed gas layer. The reliability of the equations developed was checked by validation using experimental and molecular simulation data obtained from macropore- and micropore-sized nanotubes systems respectively. Furthermore, the equations’ performance for micropores was compared to existing theoretical shale permeability models. The subsequent sensitivity analysis showed that permeability is sensitive to the nanoscale geometry factor and adsorption mechanisms. Moreover, the relevance of the surface diffusion was found to increase as the pore size decreased. For instance, surface diffusion constituted over 50% of the apparent permeability below the 10 MPa and 5.0 MPa conditions in micro- and mesopore systems, respectively, while the Darcy scale phenomenon controlled the transport of gas in macropores. Across all diffusion regimes, the microstructure geometry and sorption dynamics significantly influenced the total diffusion of methane, particularly at low pressures and decreased pore sizes. The decline in reservoir pressure during production shifted the relative importance of the adsorption and diffusion mechanisms, consequently altering the apparent gas permeability. Therefore, reservoir management teams should take into account the dynamics of gas permeability at different pressures and representative pore sizes throughout the life cycle of the asset.

ACS Style

Clement Afagwu; Saad Alafnan; Mohamed A. Mahmoud; Shirish Patil. Permeability model for shale and ultra-tight gas formations: Critical insights into the impact of dynamic adsorption. Energy Reports 2021, 7, 3302 -3316.

AMA Style

Clement Afagwu, Saad Alafnan, Mohamed A. Mahmoud, Shirish Patil. Permeability model for shale and ultra-tight gas formations: Critical insights into the impact of dynamic adsorption. Energy Reports. 2021; 7 ():3302-3316.

Chicago/Turabian Style

Clement Afagwu; Saad Alafnan; Mohamed A. Mahmoud; Shirish Patil. 2021. "Permeability model for shale and ultra-tight gas formations: Critical insights into the impact of dynamic adsorption." Energy Reports 7, no. : 3302-3316.

Journal article
Published: 27 May 2021 in Journal of Natural Gas Science and Engineering
Reads 0
Downloads 0

The temperature has a significant impact on acid stimulation efficiency in carbonate reservoirs. To fully understand its effect, this study utilizes a two-scale continuum model coupled with heat transfer. The study investigated the importance of the heat of reaction, injected acid temperature, and reservoir temperature on wormhole propagation and treatment efficiency. This research's novelty stems from its application to limestone, dolomite, and combined mineralogy in radial and linear flow patterns. It also investigated the role of vugs on acidizing efficiency in dolomite formations, showing that vugs improve wormhole penetration distance. The model reproduced the outcomes from the literature, showing that the heat of reaction has a negligible effect on wormhole propagation. On the contrary, increasing the injected acid temperature reduced the wormhole radius in limestone but improved its efficiency in dolomite. The acid could not create efficient wormholes at low acid temperatures in dolomite formation. It diverted itself towards the limestone in sequence mineralogy cases. Nevertheless, it equally stimulated the limestone and dolomite sections at elevated acid temperatures. The reservoir temperature was less critical than the acid temperature in determining the wormhole size and treatment efficiency. The model can be used to select the optimum temperature at which the most efficient wormhole is created.

ACS Style

Murtada Saleh Aljawad; Hamzah Aboluhom; Mateus Palharini Schwalbert; Adnan Al-Mubarak; Saad Alafnan; Mohamed Mahmoud. Temperature impact on linear and radial wormhole propagation in limestone, dolomite, and mixed mineralogy. Journal of Natural Gas Science and Engineering 2021, 93, 104031 .

AMA Style

Murtada Saleh Aljawad, Hamzah Aboluhom, Mateus Palharini Schwalbert, Adnan Al-Mubarak, Saad Alafnan, Mohamed Mahmoud. Temperature impact on linear and radial wormhole propagation in limestone, dolomite, and mixed mineralogy. Journal of Natural Gas Science and Engineering. 2021; 93 ():104031.

Chicago/Turabian Style

Murtada Saleh Aljawad; Hamzah Aboluhom; Mateus Palharini Schwalbert; Adnan Al-Mubarak; Saad Alafnan; Mohamed Mahmoud. 2021. "Temperature impact on linear and radial wormhole propagation in limestone, dolomite, and mixed mineralogy." Journal of Natural Gas Science and Engineering 93, no. : 104031.

Journal article
Published: 13 May 2021 in Journal of Energy Resources Technology
Reads 0
Downloads 0

Young's modulus is a principle geomechanical property that reflects the material stiffness. Good knowledge about rock mechanical properties significantly facilitates fracturing design and in situ stresses estimation. Conventionally, rock elastic properties are estimated either experimentally or using well log data, known as static and dynamic, respectively. Conducting experiments on core samples is costly, time consuming, and does not provide continuous information. While dynamic Young's modulus provides a complete profile, however, it needs the availability of acoustic logs, and its estimations differ from the static values. The objective of this article is to create a continuous profile of Young's modulus using the drilling rig sensors records. The presented approach relies on the fact that the drilling data such as drill pipe torque, weight on bit, and rate of penetration are available at an early stage without additional cost. Three machine learning algorithms were used to correlate the drilling data with Young's modulus: random forest, adaptive neuro-fuzzy inference system, and functional network. Two different datasets were used in this study, one construct and test the model, while the other was hidden from the algorithms and used later to validate the built models. The two datasets contain over 3900 data points and cover different types of rocks. Two out of the three methods utilized yielded a remarkable match between the given and the predicted values. The correlation coefficients ranged between 0.92 and 0.99 average absolute percentage errors were less than 13%. Supported by these results, the utilization of drilling data and artificial intelligence techniques to predict the elastic moduli is promising. This approach could be investigated for other geomechanical properties, besides the performance of other machine learning methods for the same purpose.

ACS Style

Osama Mutrif Siddig; Saad Fahaid Al-Afnan; Salaheldin Mahmoud Elkatatny; Abdulazeez Abdulraheem. Drilling Data-Based Approach to Build a Continuous Static Elastic Moduli Profile Utilizing Artificial Intelligence Techniques. Journal of Energy Resources Technology 2021, 144, 1 .

AMA Style

Osama Mutrif Siddig, Saad Fahaid Al-Afnan, Salaheldin Mahmoud Elkatatny, Abdulazeez Abdulraheem. Drilling Data-Based Approach to Build a Continuous Static Elastic Moduli Profile Utilizing Artificial Intelligence Techniques. Journal of Energy Resources Technology. 2021; 144 (2):1.

Chicago/Turabian Style

Osama Mutrif Siddig; Saad Fahaid Al-Afnan; Salaheldin Mahmoud Elkatatny; Abdulazeez Abdulraheem. 2021. "Drilling Data-Based Approach to Build a Continuous Static Elastic Moduli Profile Utilizing Artificial Intelligence Techniques." Journal of Energy Resources Technology 144, no. 2: 1.

Research article
Published: 30 March 2021 in ACS Omega
Reads 0
Downloads 0

Combining hydraulic fracturing with lateral drilling has allowed for economical hydrocarbon production from unconventional formations. Nevertheless, beyond hydraulic fracturing, our understanding of how hydrocarbons are stored and transported from the stimulated volume of a reservoir is still limited. Source rocks consist of organic materials finely dispersed within an inorganic matrix. Despite their small size, these organic pockets are capable of storing significant amounts of hydrocarbon due to their large surface area. The extent of the source rock’s storage capacity is determined by several factors, including the natural fracture abundancy, organic material content, type, and level of maturity. The petrophysical properties of organic materials, also known as kerogens, are subject to a high degree of uncertainty. Kerogens are difficult to isolate experimentally, which hinders accurate petrophysical analysis. The objective of this research was to use a molecular modeling approach to explore the petrophysical characteristics of kerogen. Kerogen macromolecules of different types and maturity levels were recreated via a computational platform. Then nanoporous structures representing these kerogens were obtained and characterized. Several elemental parameters, including porosity, density, pore size distribution, and adsorption capacity were closely delineated. The kerogen properties were found to correlate with the kerogen type and thermal maturity level. Kerogen type III showed the highest storage capacity, followed by types II and I, in a descending order. Moreover, in the same type of kerogen, a general trend of increasing storage capacity was observed as the maturity level increased. Methane adsorption capacity was modeled as a function of kerogen porosity. A transition flow regime was found to be the predominant mechanism. Such observations have significant implications for reservoir-scale modeling of unconventional resources.

ACS Style

Saad Alafnan. Petrophysics of Kerogens Based on Realistic Structures. ACS Omega 2021, 6, 9549 -9558.

AMA Style

Saad Alafnan. Petrophysics of Kerogens Based on Realistic Structures. ACS Omega. 2021; 6 (14):9549-9558.

Chicago/Turabian Style

Saad Alafnan. 2021. "Petrophysics of Kerogens Based on Realistic Structures." ACS Omega 6, no. 14: 9549-9558.

Journal article
Published: 16 February 2021 in Energy Reports
Reads 0
Downloads 0

The presence of asphaltenes and polar compounds in a crude oil plays a major role in dictating the type of wettability it displays with oil reservoir rocks. The main objective of this study was to investigate the effect of the asphaltenes structure and other polar compounds in altering rock wettability. Five, natural crude oil samples were used with varying asphaltene (6.4 to 11.6), total nitrogen (0.029 to 0.097) and sulfur (2.259 to 4.234) contents, all in mass%. Crude oil characterization showed the asphaltene samples to consist of condensed hydrocarbon and sulfur aromatic molecules with one or two sulfur atoms per molecule. The weight-average numbers of fused aromatic rings for hydrocarbon molecules were 6 to 7 and for sulfur-containing molecules was an average of 8 aromatic rings, where the aromatic systems were substituted with short alkyl chains of less than 20 carbon atoms. Based on mass spectral evidence, the average empirical molecular structures of the asphaltenes were constructed and they were all found to be relatively similar. Entrained maltene species with 2 to 5 aromatic rings with longer alkyl chains were also found. Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) was used to characterize each crudes’ asphaltenes fractions. Three rock samples with mineral compositions of 100% dolomite (D100), 100% calcite (C100), and 63% calcite + 37% dolomite (C63D37) were used. Variation of the contact angle with time was measured using brine, as the external phase, and the five crudes on the rock samples. The interfacial tension (IFT) between brine and the five crudes were also measured. Among the five crude types, the three rocks show the strongest wetting tendency when contacted by type V oil. These were 129.2°, 109.2°, and 135.1° for D100, C100 and C63D37, respectively. Interestingly, wettability was not linearly correlated with asphaltene contents for all crude types. Wettability varied with the rock sample, nitrogen and sulfur contents, and crude’s non-asphaltenic composition. As a result, there is no strong evidence suggesting that the content nor the structure of the asphaltenes alone has a large effect on altering rock wettability.

ACS Style

Mohammad H. Alqam; Sidqi A. Abu-Khamsin; Abdullah S. Sultan; Saad F. Al-Afnan; Nadrah A. Alawani. An investigation of factors influencing carbonate rock wettability. Energy Reports 2021, 7, 1125 -1132.

AMA Style

Mohammad H. Alqam, Sidqi A. Abu-Khamsin, Abdullah S. Sultan, Saad F. Al-Afnan, Nadrah A. Alawani. An investigation of factors influencing carbonate rock wettability. Energy Reports. 2021; 7 ():1125-1132.

Chicago/Turabian Style

Mohammad H. Alqam; Sidqi A. Abu-Khamsin; Abdullah S. Sultan; Saad F. Al-Afnan; Nadrah A. Alawani. 2021. "An investigation of factors influencing carbonate rock wettability." Energy Reports 7, no. : 1125-1132.

Research article
Published: 05 January 2021 in ACS Omega
Reads 0
Downloads 0

Removal of oil field scales commonly requires low pH acid, which may cause many issues under downhole conditions. Because of the deposition of different scale types and the economic effect, there is a need to develop a remedial descaling fluid that can be effectively used to remove different types of scales at a different position in the well. This paper provides a new scale dissolver that is noncorrosive and has high scale dissolution performance for composite scales. This study shows a series of comprehensive experimental lab tests as scale characterization, equilibrium brine compositional analysis, fluid compatibility and stability, solubility test, precipitation tendency for the dissolved solids, corrosion test, and core flooding. The scale samples contain magnetite, kaolinite, calcium carbonate, and sulfate scales. The results showed that the dissolution rate was higher than 74% for composite field scale samples after 6 h at 70 °C, while the new dissolver completely dissolved the two samples at 100 °C after 5 h. The new dissolver outperformed the common commercial dissolver used in the oil and gas industry. The new dissolver has a pH of 9 and showed safe use regarding the precipitation of dissolved solids that can be produced during the scale treatment and a low corrosion rate of 0.063 kg/m2 at 6.9 MPa and 100 °C for 6 h. Also, the new dissolver was tested through core flooding for Indiana limestone and showed core permeability enhancement; the treatment with the new dissolver enhanced the core permeability from an initial value of 0.67 milliDarcy (mD) to record 1.29 mD.

ACS Style

Hany Gamal; Salaheldin Elkatatny; Saad Al-Afnan; Mohamed Bahgat. Development of a Unique Organic Acid Solution for Removing Composite Field Scales. ACS Omega 2021, 6, 1205 -1215.

AMA Style

Hany Gamal, Salaheldin Elkatatny, Saad Al-Afnan, Mohamed Bahgat. Development of a Unique Organic Acid Solution for Removing Composite Field Scales. ACS Omega. 2021; 6 (2):1205-1215.

Chicago/Turabian Style

Hany Gamal; Salaheldin Elkatatny; Saad Al-Afnan; Mohamed Bahgat. 2021. "Development of a Unique Organic Acid Solution for Removing Composite Field Scales." ACS Omega 6, no. 2: 1205-1215.

Review
Published: 18 December 2020 in Sustainability
Reads 0
Downloads 0

A continuous growth in the global economy and population requires a sustainable energy supply. Maximizing recovery factor out of the naturally occurring hydrocarbons resources has been an active area of continuous development to meet the globally increasing demand for energy. Coalbed methane (CBM), which is one of the primary resources of natural gas, associates complex storage mechanisms and requires some advanced recovery techniques, rendering conventional reserve assessment methods insufficient. This work presents a literature review on CBM in different aspects. This includes rock characteristics such as porosity, permeability, adsorption capacity, adsorption isotherm, and coal classification. In addition, CBM reservoirs are compared to conventional reservoirs in terms of reservoir quality, reservoir properties, accumulation, and water/gas saturation and production. Different topics that contribute to the production of CBM reservoirs are also discussed. This includes production mechanisms, well spacing, well completion, and petrophysical interpretations. The main part of this work sheds a light on the available techniques to determine initial-gas-in-place in CBM reservoirs such as volumetric, decline curve, and material balance. It also presents the pros and cons of each technique. Lastly, common development and economic challenges in CBM fields are listed in addition to environmental concerns.

ACS Style

Ali Altowilib; Ahmed AlSaihati; Hussain Alhamood; Saad Alafnan; Sulaiman Alarifi. Reserves Estimation for Coalbed Methane Reservoirs: A Review. Sustainability 2020, 12, 10621 .

AMA Style

Ali Altowilib, Ahmed AlSaihati, Hussain Alhamood, Saad Alafnan, Sulaiman Alarifi. Reserves Estimation for Coalbed Methane Reservoirs: A Review. Sustainability. 2020; 12 (24):10621.

Chicago/Turabian Style

Ali Altowilib; Ahmed AlSaihati; Hussain Alhamood; Saad Alafnan; Sulaiman Alarifi. 2020. "Reserves Estimation for Coalbed Methane Reservoirs: A Review." Sustainability 12, no. 24: 10621.

Research article
Published: 19 November 2020 in Energy & Fuels
Reads 0
Downloads 0

Petroleum engineers are always in a race to maximize the recovery factor out of naturally trapped hydrocarbon resources. Unconventional resources such as organic-rich shales have unlocked significant reserves attributed to the novel production technologies of lateral drilling assisted by hydraulic fracturing. Even though such techniques have enabled the exploitation of shales, the ultimate recovery remained fractional, a challenge to be answered through further improvement. Carbon dioxide injection in unconventional resources, which was initially implemented for coalbed methane, has been recently an active area of investigation for organic-rich shales. In this paper, we present a molecular modeling study of carbon dioxide injection in the organic matter of the shale matrix. We built the molecular model, consistent with the repeated organic matter characterization in the literature. Molecular dynamics (MD) protocol was developed to form a three-dimensional (3-D) configuration of kerogen, followed by Gibbs Monte Carlo simulation for the adsorption/desorption calculations, and self-diffusivity calculations through MD. The aim was to delineate the impact of carbon dioxide injection on the adsorption/desorption behavior coupled with its influence on the transport. Injection of carbon dioxide was found to shift the adsorption isotherm favoring the depletion of methane. The ultimate recovery raised from 54% (no injection of CO2) up to 92% depending on the carbon dioxide concentration and its temperature. Moreover, the injection of carbon dioxide was found to have a minimal impact on the self-diffusivity of methane in kerogen bodies and their associated microcracks.

ACS Style

Saad AlAfnan; Yusuf Falola; Osamah Al Mansour; Khalid Alsamadony; Abeeb Awotunde; Murtada Aljawad. Enhanced Recovery From Organic-Rich Shales through Carbon Dioxide Injection: Molecular-Level Investigation. Energy & Fuels 2020, 34, 16089 -16098.

AMA Style

Saad AlAfnan, Yusuf Falola, Osamah Al Mansour, Khalid Alsamadony, Abeeb Awotunde, Murtada Aljawad. Enhanced Recovery From Organic-Rich Shales through Carbon Dioxide Injection: Molecular-Level Investigation. Energy & Fuels. 2020; 34 (12):16089-16098.

Chicago/Turabian Style

Saad AlAfnan; Yusuf Falola; Osamah Al Mansour; Khalid Alsamadony; Abeeb Awotunde; Murtada Aljawad. 2020. "Enhanced Recovery From Organic-Rich Shales through Carbon Dioxide Injection: Molecular-Level Investigation." Energy & Fuels 34, no. 12: 16089-16098.

Review
Published: 22 September 2020 in Petroleum Science
Reads 0
Downloads 0

A review of the pressure transient analysis of flow in reservoirs having natural fractures, vugs and/or caves is presented to provide an insight into how much knowledge has been acquired about this phenomenon and to highlight the gaps still open for further research. A comparison-based approach is adopted which involved the review of works by several authors and identifying the limiting assumptions, model restrictions and applicability. Pressure transient analysis provides information to aid the identification of important features of reservoirs. It also provides an explanation to complex reservoir pressure-dependent variations which have led to improved understanding and optimization of the reservoir dynamics. Pressure transient analysis techniques, however, have limitations as not all its models find application in naturally fractured and vuggy reservoirs as the flow dynamics differ considerably. Pollard’s model presented in 1953 provided the foundation for existing pressure transient analysis in these types of reservoirs, and since then, several authors have modified this basic model and come up with more accurate models to characterize the dynamic pressure behavior in reservoirs with natural fractures, vugs and/or caves, with most having inherent limitations. This paper summarizes what has been done, what knowledge is considered established and the gaps left to be researched on.

ACS Style

Isah Mohammed; Teslim O. Olayiwola; Murtadha Alkathim; Abeeb A. Awotunde; Saad F. Alafnan. A review of pressure transient analysis in reservoirs with natural fractures, vugs and/or caves. Petroleum Science 2020, 18, 154 -172.

AMA Style

Isah Mohammed, Teslim O. Olayiwola, Murtadha Alkathim, Abeeb A. Awotunde, Saad F. Alafnan. A review of pressure transient analysis in reservoirs with natural fractures, vugs and/or caves. Petroleum Science. 2020; 18 (1):154-172.

Chicago/Turabian Style

Isah Mohammed; Teslim O. Olayiwola; Murtadha Alkathim; Abeeb A. Awotunde; Saad F. Alafnan. 2020. "A review of pressure transient analysis in reservoirs with natural fractures, vugs and/or caves." Petroleum Science 18, no. 1: 154-172.

Journal article
Published: 18 August 2020 in Molecules
Reads 0
Downloads 0

The presence of kerogen in source rocks gives rise to a plethora of potential gas storage mechanisms. Proper estimation of the gas reserve requires knowledge of the quantities of free and adsorbed gas in rock pores and kerogen. Traditional methods of reserve estimation such as the volumetric and material balance approaches are insufficient because they do not consider both the free and adsorbed gas compartments present in kerogens. Modified versions of these equations are based on adding terms to account for hydrocarbons stored in kerogen. None of the existing models considered the effect of kerogen maturing on methane gas adsorption. In this work, a molecular modeling was employed to explore how thermal maturity impacts gas adsorption in kerogen. Four different macromolecules of kerogen were included to mimic kerogens of different maturity levels; these were folded to more closely resemble the nanoporous kerogen structures of source rocks. These structures form the basis of the modeling necessary to assess the adsorption capacity as a function of the structure. The number of double bonds plus the number and type of heteroatoms (O, S, and N) were found to influence the final configuration of the kerogen structures, and hence their capacity to host methane molecules. The degree of aromaticity increased with the maturity level within the same kerogen type. The fraction of aromaticity gives rise to the polarity. We present an empirical mathematical relationship that makes possible the estimation of the adsorption capacity of kerogen based on the degree of polarity. Variations in kerogen adsorption capacity have significant implications on the reservoir scale. The general trend obtained from the molecular modeling was found to be consistent with experimental measurements done on actual kerogen samples. Shale samples with different kerogen content and with different maturity showed that shales with immature kerogen have small methane adsorption capacity compared to shales with mature kerogen. In this study, it is shown for the first time that the key factor to control natural gas adsorption is the kerogen maturity not the kerogen content.

ACS Style

Saad AlAfnan; Theis Solling; Mohamed Mahmoud. Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach. Molecules 2020, 25, 3764 .

AMA Style

Saad AlAfnan, Theis Solling, Mohamed Mahmoud. Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach. Molecules. 2020; 25 (16):3764.

Chicago/Turabian Style

Saad AlAfnan; Theis Solling; Mohamed Mahmoud. 2020. "Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach." Molecules 25, no. 16: 3764.

Research article
Published: 24 July 2020 in ACS Omega
Reads 0
Downloads 0

Hydrocarbons that are transported in a hierarchal path from the nanoporous constituents of a shale matrix to natural and then hydraulic fractures are subject to continuous fractionation during the journey. The organic nanopores of a source rock matrix known as kerogen have pore sizes on the angstrom scale. At that degree of confinement, pores can act as a selective membrane, preferentially maintaining some components over the others in a continuous fractionation phenomenon that alters the adsorption/desorption isotherm. Several studies have considered the adsorption/desorption behavior of kerogen on the basis of a single component. In reality, methane is associated with other hydrocarbons, making that assumption questionable. The present work investigates the multicomponent gas sorption of kerogen structures via a molecular computational approach. The continuous fractionation results in the accumulation of heavier components. The compositional changes alter the phase behavior, enlarging the anticipated two-phase regime. Additionally, the ability of molecules to diffuse from kerogen was also found to be affected by the fractionation effect. These microscale effects provide some insights into the potential factors that influence the productivity at the reservoir scale.

ACS Style

Saad AlAfnan; Abdullah S. Sultan; Jaber Aljaberi. Molecular Fractionation in the Organic Materials of Source Rocks. ACS Omega 2020, 5, 18968 -18974.

AMA Style

Saad AlAfnan, Abdullah S. Sultan, Jaber Aljaberi. Molecular Fractionation in the Organic Materials of Source Rocks. ACS Omega. 2020; 5 (30):18968-18974.

Chicago/Turabian Style

Saad AlAfnan; Abdullah S. Sultan; Jaber Aljaberi. 2020. "Molecular Fractionation in the Organic Materials of Source Rocks." ACS Omega 5, no. 30: 18968-18974.

Journal article
Published: 22 April 2020 in Sustainability
Reads 0
Downloads 0

An impermeable layer “filter cake” usually forms during the overbalanced drilling technique. Even though it helps in protecting the formation from a further invasion of drilling fluids, the removal of this layer is essential for a proper cement job and to avoid any reduction in wellbore deliverability. The design of the removal process is complicated and depends on the filter cake composition and homogeneity. This paper presents an experimental evaluation on the usage of a novel cake washer (NCW) in the removal of a filter cake formed by an invert emulsion oil-based drilling fluid that contains calcium carbonate as a weighting material while drilling a horizontal reservoir. The proposed NCW is a mixture of organic acid, mutual solvent and nonionic surfactant. It is designed to enable restored wellbore permeability for a sustainable production. Since the filter cake mainly consists of the weighting material, the solubility of calcium carbonate in NCW at different ranges of temperature, duration and concentration was investigated. An actual casing joint was used to test the corrosion possibility of the treating solution. High-pressure and high-temperature (HPHT) filtration tests on ceramic discs and Berea sandstone core samples were conducted to measure the efficiency of the filter cake removal and the retained permeability. Ethylene glycol mono butyl ether (EGMBE) was used as a mutual solvent and the solubility was higher compared to when the mutual solvent was not used in the washer formulation. A significant increase in calcium carbonate dissolution with time was observed for a duration of 24 h. The solubility was found to be proportional to the concentration of NCW with optimum results of 99% removal at a temperature of around 212 °F. At those conditions, no major corrosion problems were detected. Permeability of the core retained its pristine value after the treatment.

ACS Style

Osama Siddig; Saad Al-Afnan; Salaheldin Elkatatny; Mohamed Bahgat. Novel Cake Washer for Removing Oil-Based Calcium Carbonate Filter Cake in Horizontal Wells. Sustainability 2020, 12, 3427 .

AMA Style

Osama Siddig, Saad Al-Afnan, Salaheldin Elkatatny, Mohamed Bahgat. Novel Cake Washer for Removing Oil-Based Calcium Carbonate Filter Cake in Horizontal Wells. Sustainability. 2020; 12 (8):3427.

Chicago/Turabian Style

Osama Siddig; Saad Al-Afnan; Salaheldin Elkatatny; Mohamed Bahgat. 2020. "Novel Cake Washer for Removing Oil-Based Calcium Carbonate Filter Cake in Horizontal Wells." Sustainability 12, no. 8: 3427.

Review
Published: 16 April 2020 in Journal of Natural Gas Science and Engineering
Reads 0
Downloads 0

The characteristics of shale formations are different from other typical sedimentary formations. They are stress-sensitive rocks with contained fluids subject to rapid adsorption and desorption activities. Importantly, the flow of fluids in shale reservoirs is pressure-dependent and of a non-Darcy nature. For these reasons, the typical pressure-transient analyses are not applicable to these low-permeability reservoirs. Although several modifications to conventional analyses have been proposed, there are still a number of gaps in the proper characterization of shale gas and oil reservoirs. In this research, we reviewed the literature on pressure-transient analysis in shale reservoirs, presented the limitations of the proposed methods, and suggested future research directions for improved interpretation of transient pressure data.

ACS Style

Clement Afagwu; Isah Abubakar; Shams Kalam; Saad F. Al-Afnan; Abeeb A. Awotunde. Pressure-transient analysis in shale gas reservoirs: A review. Journal of Natural Gas Science and Engineering 2020, 78, 103319 .

AMA Style

Clement Afagwu, Isah Abubakar, Shams Kalam, Saad F. Al-Afnan, Abeeb A. Awotunde. Pressure-transient analysis in shale gas reservoirs: A review. Journal of Natural Gas Science and Engineering. 2020; 78 ():103319.

Chicago/Turabian Style

Clement Afagwu; Isah Abubakar; Shams Kalam; Saad F. Al-Afnan; Abeeb A. Awotunde. 2020. "Pressure-transient analysis in shale gas reservoirs: A review." Journal of Natural Gas Science and Engineering 78, no. : 103319.

Journal article
Published: 30 March 2020 in Sustainability
Reads 0
Downloads 0

Barite sag is a challenging phenomenon encountered in deep drilling with barite-weighted fluids and associated with fluid stability. It can take place in vertical and directional wells, whether in dynamic or static conditions. In this study, an anti-sagging urea-based additive was evaluated to enhance fluid stability and prevent solids sag in water-based fluids to be used in drilling, completion, and workover operations. A barite-weighted drilling fluid, with a density of 15 ppg, was used with the main drilling fluid additives. The ratio of the urea-based additive was varied in the range 0.25–3.0 vol.% of the total base fluid. The impact of this anti-sagging agent on the sag tendency was evaluated at 250 °F using vertical and inclined sag tests. The optimum concentration of the anti-sagging agent was determined for both vertical and inclined wells. The effect of the urea-additive on the drilling fluid rheology was investigated at low and high temperatures (80 °F and 250 °F). Furthermore, the impact of the urea-additive on the filtration performance of the drilling fluid was studied at 250 °F. Adding the urea-additive to the drilling fluid improved the stability of the drilling fluid, as indicated by a reduction in the sag factor. The optimum concentration of this additive was found to be 0.5–1.0 vol.% of the base fluid. This concentration was enough to prevent barite sag in both vertical and inclined conditions at 250 °F, with a sag factor of around 0.5. For the optimum concentration, the yield point and gel strength (after 10 s) were improved by around 50% and 45%, respectively, while both the plastic viscosity and gel strength (after 10 min) were maintained at the desired levels. Moreover, the anti-sagging agent has no impact on drilling fluid density, pH, or filtration performance.

ACS Style

Abdelmjeed Mohamed; Saad Al-Afnan; Salaheldin Elkatatny; Ibnelwaleed Hussein. Prevention of Barite Sag in Water-Based Drilling Fluids by A Urea-Based Additive for Drilling Deep Formations. Sustainability 2020, 12, 2719 .

AMA Style

Abdelmjeed Mohamed, Saad Al-Afnan, Salaheldin Elkatatny, Ibnelwaleed Hussein. Prevention of Barite Sag in Water-Based Drilling Fluids by A Urea-Based Additive for Drilling Deep Formations. Sustainability. 2020; 12 (7):2719.

Chicago/Turabian Style

Abdelmjeed Mohamed; Saad Al-Afnan; Salaheldin Elkatatny; Ibnelwaleed Hussein. 2020. "Prevention of Barite Sag in Water-Based Drilling Fluids by A Urea-Based Additive for Drilling Deep Formations." Sustainability 12, no. 7: 2719.

Journal article
Published: 10 March 2020 in Sustainability
Reads 0
Downloads 0

Advancements in drilling and production technologies have made exploiting resources, which for long time were labeled unproducible such as shales, as economically feasible. In particular, lateral drilling coupled with hydraulic fracturing has created means for hydrocarbons to be transported from the shale matrix through the stimulated network of microcracks, natural fractures, and hydraulic fractures to the wellbore. Because of the degree of confinement, the ultimate recovery is just a small fraction of the total hydrocarbons in place. Our aim was to investigate how augmented pressure gradient through hydraulic fracturing when coupled with another derive mechanism such as heating can improve the overall recovery for more sustainable exploitation of unconventional resources. Knowledge on how hydrocarbons are stored and transported within the shale matrix is uncertain. Shale matrix, which consists of organic and inorganic constituents, have pore sizes of few nanometers, a degree of confinement at which our typical reservoir engineering models break down. These intricacies hinder any thorough investigations of hydrocarbon production from shale matrix under the influence of pressure and thermal gradients. Kerogen, which represents the solid part of the organic materials in shales, serves as form of nanoporous media, where hydrocarbons are stored and then expelled after shale stimulation procedure. In this work, a computational representation of a kerogen–hydrocarbon system was replicated to study the depletion process under coupled mechanisms of pressure and temperature. The extent of production enhancement because of increasing temperature was shown. Moreover, heating requirements to achieve the enhancement at reservoir scale was also presented to assess the sustainability of the proposed method.

ACS Style

Saad Alafnan; Murtada Aljawad; Guenther Glatz; Abdullah Sultan; Rene Windiks. Sustainable Production from Shale Gas Resources through Heat-Assisted Depletion. Sustainability 2020, 12, 2145 .

AMA Style

Saad Alafnan, Murtada Aljawad, Guenther Glatz, Abdullah Sultan, Rene Windiks. Sustainable Production from Shale Gas Resources through Heat-Assisted Depletion. Sustainability. 2020; 12 (5):2145.

Chicago/Turabian Style

Saad Alafnan; Murtada Aljawad; Guenther Glatz; Abdullah Sultan; Rene Windiks. 2020. "Sustainable Production from Shale Gas Resources through Heat-Assisted Depletion." Sustainability 12, no. 5: 2145.

Journal article
Published: 17 January 2020 in Sustainability
Reads 0
Downloads 0

Synthetic well log generation using artificial intelligence tools is a robust solution for situations in which logging data are not available or are partially lost. Formation bulk density (RHOB) logging data greatly assist in identifying downhole formations. These data are measured in the field while drilling by using a density log tool in the form of either a logging while drilling (LWD) technique or (more often) by wireline logging after the formations are drilled. This is due to operational limitations during the drilling process. Therefore, the objective of this study was to develop a predictive tool for estimating RHOB while drilling using an adaptive network-based fuzzy interference system (ANFIS), functional network (FN), and support vector machine (SVM). The proposed model uses the mechanical drilling constraints as feeding input parameters, and the conventional RHOB log data as an output parameter. These mechanical drilling parameters are usually measured while drilling, and their responses vary with different formations. A dataset of 2400 actual datapoints, obtained from a horizontal well in the Middle East, were used to build the proposed models. The obtained dataset was divided into a 70/30 ratio for model training and testing, respectively. The optimized ANFIS-based model outperformed the FN- and SVM-based models with a correlation coefficient (R) of 0.93, and average absolute percentage error (AAPE) of 0.81% between the predicted and measured RHOB values. These results demonstrate the reliability of the developed ANFIS model for predicting RHOB while drilling, based on the mechanical drilling parameters. Subsequently, the ANFIS-based model was validated using unseen data from another well within the same field. The validation process yielded an AAPE of 0.97% between the predicted and actual RHOB values, which confirmed the robustness of the developed model as an effective predictive tool for RHOB.

ACS Style

Ahmed Gowida; Salaheldin Elkatatny; Saad Al-Afnan; Abdulazeez Abdulraheem. New Computational Artificial Intelligence Models for Generating Synthetic Formation Bulk Density Logs While Drilling. Sustainability 2020, 12, 686 .

AMA Style

Ahmed Gowida, Salaheldin Elkatatny, Saad Al-Afnan, Abdulazeez Abdulraheem. New Computational Artificial Intelligence Models for Generating Synthetic Formation Bulk Density Logs While Drilling. Sustainability. 2020; 12 (2):686.

Chicago/Turabian Style

Ahmed Gowida; Salaheldin Elkatatny; Saad Al-Afnan; Abdulazeez Abdulraheem. 2020. "New Computational Artificial Intelligence Models for Generating Synthetic Formation Bulk Density Logs While Drilling." Sustainability 12, no. 2: 686.

Research article
Published: 12 November 2019 in ACS Omega
Reads 0
Downloads 0

The improvement of heavy oil recovery by steam injection or electric heating has been investigated extensively. However, the potential benefit of placing a permanent heating element around the pay zone has not received significant attention. Previously, numerical models were mainly used to investigate improvements in reservoir fluid mobility but rarely when considering the impact of downhole heating on a wellbore’s vertical lift performance. In this study, a coupled mass and heat transfer model was developed and applied to a reservoir/wellbore system to investigate the impact of a heating element on recovery improvement. The numerical simulations showed that heat propagation due to the heating element did not exceed 10–15 ft while the reservoir’s fluids were being produced. However, much longer distances could be reached through heat conduction under shut-in conditions. It was determined that more than a 40% improvement in the productivity index could be achieved at low production rates. However, no productivity improvement was noticed under convection-dominated heat transfer, which occurs at relatively high production rates. A heating element could also reduce the flowing bottomhole pressure required in a wellbore by more than 200 psi, a result caused by a continuous temperature increase as the fluids flowed into the heated wellbore section.

ACS Style

Murtada Saleh Aljawad; Saad Alafnan; Sidqi Abu-Khamsin. Artificial Lift and Mobility Enhancement of Heavy Oil Reservoirs Utilizing a Renewable Energy-Powered Heating Element. ACS Omega 2019, 4, 20048 -20058.

AMA Style

Murtada Saleh Aljawad, Saad Alafnan, Sidqi Abu-Khamsin. Artificial Lift and Mobility Enhancement of Heavy Oil Reservoirs Utilizing a Renewable Energy-Powered Heating Element. ACS Omega. 2019; 4 (22):20048-20058.

Chicago/Turabian Style

Murtada Saleh Aljawad; Saad Alafnan; Sidqi Abu-Khamsin. 2019. "Artificial Lift and Mobility Enhancement of Heavy Oil Reservoirs Utilizing a Renewable Energy-Powered Heating Element." ACS Omega 4, no. 22: 20048-20058.

Research article
Published: 21 August 2019 in Energy & Fuels
Reads 0
Downloads 0

Natural gas is a rapidly growing source of energy, supplying more than a quarter of the global demand for power. Gas condensate is one type of natural gas resource in which liquid dropout can occur as the pressure decreases throughout the lifetime of the reservoir. This behavior can severely affect the productivity of the reservoir. Chemical and mechanical treatments are applied to repair such damage and restore the productivity of the well. While these types of approaches can yield some success, there is a need for more proactive strategies to eliminate this problem and minimize interference. In this research, we present a dynamic evaluation of the use of an integrated downhole heating system, where renewable energy serves as a source of downhole heating for more sustainable productivity throughout the gas condensate reservoir lifetime. The downhole heating efficiency is significantly influenced by the production rate because some portion of heat is removed with the produced gas. For that purpose, surface and subsurface calculations are coupled to investigate the limitations and the power requirements of renewable energy sources. Our study presents an integrated engineering analysis through simultaneous solving of mass and heat transfer equations coupled with surface renewable energy requirement. The presented study demonstrates the viable feasibility of this method for avoiding gas condensate problems and enhancing ultimate recovery.

ACS Style

Saad AlAfnan; Murtada Aljawad; Fahad Alismail; Abdulaziz Almajed. Enhanced Recovery from Gas Condensate Reservoirs through Renewable Energy Sources. Energy & Fuels 2019, 33, 10115 -10122.

AMA Style

Saad AlAfnan, Murtada Aljawad, Fahad Alismail, Abdulaziz Almajed. Enhanced Recovery from Gas Condensate Reservoirs through Renewable Energy Sources. Energy & Fuels. 2019; 33 (10):10115-10122.

Chicago/Turabian Style

Saad AlAfnan; Murtada Aljawad; Fahad Alismail; Abdulaziz Almajed. 2019. "Enhanced Recovery from Gas Condensate Reservoirs through Renewable Energy Sources." Energy & Fuels 33, no. 10: 10115-10122.