bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sequential Mineralogy Characterization of Organic-Rich Shale: Example from the Hanadir Shale, Northwest Saudi Arabia
Authors: Abouelresh M. , Babalola L. , Al-Ghamdi T. , Al-Abdullatif A. , El Hajj H. 
Published: July 2016

Abstract
The Middle Ordovician (Middle to Late Cardocian) Hanadir Shale member of the Qasim Formation is a potential shale gas exploration target. This paper quantitatively characterizes the mineralogy of the Hanadir Shale using an applied methodology to better understand the interrelationship between mineralogy and reservoir properties of shale gas formations.
A 9-m thick sequence of the Hanadir Shale within the Tabuk quadrangle in northwest Saudi Arabia was investigated using sedimentological, geochemical, and mineralogical analyses. Sequential analyses were performed on shale samples: X-ray diffraction (XRD), X-ray fluorescence (XRF), cations exchange capacity (CEC), and linear swelling meter (LSM). This shale sequence is dominantly comprised of laminated clay-rich shale interbedded with thin siltstone to very fine sandstone beds. It is overlying a 5-m thick bearing with massive-to-low-angle crossbedding in the uppermost intervals of the Sajir member of the Saq Formation and underlying 30-m thick tigillites in the Kahfah member.
The XRD results showed the Hanadir Shale is characterized by similar mineralogical composition of different proportions with all the samples containing high silica content (~50%), K-feldspar (~30%), and Na-feldspar (3%). Compared to the bulk mineralogy of the shale gas, clay content in the samples (10 to 20%) is relatively low. The identified clay types include kaolinite, illite, and smectite. Carbonate minerals (calcite and dolomite) also occur as traces (~1%) in all the samples. Swelling tests were performed to understand the swelling properties of the clay content and better understand reservoir properties, performance, and fluid properties in the Qasim Shale's reservoir equivalents. The study contributes to the existing database of shale gas exploration information.
Clay mineral distribution patterns and their effects on the reservoir quality of the unconventional shale gas are not well understood; therefore, this study contributes to the understanding of the reservoir behavior of not only the Hanadir Shale but also other regional potential shale formations.
Permeability Prediction Based on Leaky-Capillary-Tubes Using Genetic Algorithm
Authors: Nizamuddin S. , Hossain M. Enamul , Abdulazeez A. , Hassan M. R. 
Published: July 2016

Abstract
For any reservoir, the cross-plot of permeability vs. porosity data exhibit a non-linear behavior. As a result, there is always an uncertainty associated with the characteristic parameters obtained for any permeability equation using inverse-linear-regression technique. In this paper, unique characteristic parameters of permeability equation based on Civan's leaky-tube-capillary model were determined using genetic algorithm to obtain straight-line plot of the derived permeability vs. normalized porosity data.
The statistical inverse-linear-regression techniques are more likely to end up in a local minimum without ever finding the global minimum. Consequently, it results in finding non-unique characteristic parameters of the permeability function. However, heuristic-based optimization technique such as genetic algorithm randomly jump out of the local minima and finds the global minimum of the permeability function. This helps in finding unique value of the characteristic parameters specifically cement exclusion factor, power law exponent, inter-connectivity parameter and other constants resulting in a high correlation coefficient of derived permeability vs. normalized porosity cross-plot.
The unique characteristic parameters obtained by global minimization of permeability function can determine a wide range of permeability values with higher accuracy. On the other hand, the non-unique parameters determined from local minimization are suitable for a limited range of porosity-permeability data. The correlation coefficients for the cross-plot of derived permeability vs. normalized porosity using unique characteristic parameters was found to be close to unity for various data sets obtained from literature. The presented method of finding parameters of a permeability function also reduces the experimentation cost and time.
The novelty of the heuristic-based optimization techniques such as genetic algorithm is in its capacity to find the global minimum of the permeability function. This helps in obtaining unique characteristic parameters for a particular set of permeability-porosity data.
An Assisted Method for Depositional Facies Mapping and Reservoir Connectivity Evaluation Based on Converted Pressure
Authors: Li Yong , Li Baozhu , Tian Changbing , Zhu Yixiang , Qian Qihao 
Published: July 2016

Abstract
Formation test pressure is one of the most important and invaluable surveillance data to understand reservoir dynamic behavior, but usually pressure of different wells are not tested at the same time which limit its function. This paper proposed a simplified material balance equation to convert all tested pressure to the same date, then use converted pressure to assist depositional facies mapping and reservoir connectivity evaluation.
Take M1 reservoir for example, all pressure data are converted to the same artificial test date with a simplified material balance equation. The material balance equation is simplified under certain assumptions, which is similar to that of volumetric undersaturated oil reservoirs. Then wells were classified into different groups for each zone according to their converted depletion pressure change behavior, and depositional facies and reservoir lateral connectivity of different groups of wells are analyzed with clear understanding and obvious characteristics.
M1 reservoir is a multi-layered sandstone reservoir under primary depletion currently, which have 18 wells conducted formation test from 2010 to 2011. It is found that pressure analysis of these wells have no obvious characteristic. But after all pressures converted to the same date with well production constrained, depletion pressure change has clear trend. Then for each zone, wells were classified into different groups according to pressure change behavior, which indicates pressure depletion is similar in the same group while much different from that of other groups. Converted pressure data were analyzed in detail for each zone and used for depositional facies mapping and reservoir connectivity evaluation. Most are consistent between pressure depletion behavior and geological understanding, but some also have contradictions which helps to revise depositional facies. For reservoir connectivity, similar results of depositional facies are drawn.
This paper offers a case study of converting pressure to the same date based on simplified material balance equation, and how to use converted pressure for depositional facies mapping and reservoir connectivity evaluation study are also detailed presented.
On Job Training OJT Accelerated Learning of Reservoir Management Engineers
Authors: AL-Muraikhi Ahmad , Shenawi Shamsuddin , Elhayek Soha 
Published: July 2016

Abstract
On Job Training (OJT) for new fresh graduate reservoir engineers has been implemented at Saudi Aramco. The workshop is offered following completion of the company run on-boarding program offered by Upstream Professional Development Center (UPDC). The objective of this new training is to accelerate the young engineers' knowledge and experience and reduce the professional gap existing in the oil industry. This is being achieved by going in detail through one of the mature reservoirs with a long production history. The young engineers are chartered with the main objective of the reservoir engineers which is the SWEEP. They are trained to conduct detailed analyses of wells and reservoir production/injection performance with the primary focus of determining the current sweep efficiency. Participants are tasked to develop solutions to improve the recovery and the sweep areally and vertically to ensure that the maximum percentage of the reserve is produced.
The number of the participants in each workshop is 12 with different level of experience varying from few months to three years. The participants come from different Up-stream organizations; Reservoir Management, Reservoir Simulation, Reservoir Description, Well testing, Facilities and Computer engineers; Geologist and Geophysicists.
The workshop starts with explaining the ROLE OF RESERVOIR MANAGEMENT. It segments the process into three main areas. The first is to understand the static nature of the reservoir mainly the matrix information. The second is the dynamic part which is the fluid movements and its properties. And the third part is the integrations between the two natures which is used to further understand the complexity of the reservoir and the inter connection between the wells.
The participants practice during their training the ability of extracting the data related to the field and analyzing it thoroughly. Then the data is put-together and integrated to explain the fluid dynamic movements. The trainees as well, develop their reservoir thinking skills by identifying the challenges and formulating future action plans to improve the sweep and maximize the oil recovery.
OJT accelerate learning of young engineers from a variety of universities around the world. This training provided a solid foundation for participants as it help them to deal with real-life examples and help them to sharpen their analyzing and thinking abilities to prepare them for the new reservoir engineering era.
Self-Organizing Maps for Regions Exploring and Identification Based on Geological Signatures Similarities and Anomalies
Authors: Dossary Mubarak , Al-Turki Ali , Harbi Badr 
Published: July 2016

Abstract
Modern reservoir simulation models include very detailed description of geology to enable accurate physics solutions. In order to increase the reliability of the simulation forecast, simulation models grew in size to a billion or more grid blocks, which poses a challenging complexity to build, validate, and history match the models. To help assess and handle new complexity and inherent uncertainties, an artificial intelligence algorithm based on Self-Organizing Maps (SOM) has been developed to explore and identify geologic model components based on similarities and dissimilarities in the model. Sector models can be generated based on these region definitions for focused region assessment, history matching, production/injection optimization, or optimal well configuration.
In this work, an unsupervised artificial intelligence neural network algorithm is devised that can combine both static properties distribution (permeability, Reservoir Quality Index (RQI), or porosity) and dynamic properties (pressures or saturations) to construct a similarities matrix. Standard deviation-based chaos minimization is then applied to merge similar regions (contiguous), identify similar but distant regions, and reduce the number of identified heterogeneous regions to the desired controlled number. The algorithm was applied on a synthetic reservoir model using the GigaPOWERS® simulator, The developed SOM-based algorithm conditions geology to reservoir dynamics, and reduce model computational requirements of assisted history matching (AHM) with minimal engineering effort.
Managing Crucial Business Decisions Related to a Wastewater Disposal System Using Hydraulic Simulation
Authors: Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Al-Subaie Fehead M. 
Published: July 2016

Abstract
Business decisions management in the petroleum industry is often constrained by a lack of representative projections, time limitation, and cost implications. Proper administrations of future amendments to existing facilities necessitate accurate predictions of proposed upgrades. The precise outcomes of hydraulic simulation have proven reliable in forecasting operational scenarios related to wastewater disposal (WWD) system. The accurate predictions of hydraulic simulation, coupled with identified time frames and monetary investments, pave the way for accountable and successful managerial decisions.
Increased water production from mature fields requires facilities to be upgraded to meet future business demands. WWDs are integral constituents of oil processing facilities as they are the conduit for responsible and environmental disposal of produced water.
Facility-A injects wastewater into five disposal wells at a given capacity. Production demands have increased, which subsequently, entail the need to avail extra injection capacity to Facility-A. Long-term plans to an entire system upgrade are well underway; yet, the demand for extra potential is imminent. Many short-term plans were conceptualized to meet the injection requirements in the interim period until the long-term upgraded facility is on stream.
A hydraulic simulation model was built and calibrated for Facility-A as a baseline model. Full system analysis of Facility-A disposal network, utilizing hydraulic simulation techniques, was performed to predict the outcome of each proposed short-term scenario. The contemplated scenarios were tapping into a nearby facility's disposal system, installing temporary injection pump at the wellheads, and adding two more injection wells to a new pipeline network.
This paper will present in depth the hydraulic simulation results of the abovementioned scenarios and highlight their feasibility as viable short term scenarios. In addition, a detailed account of the associated time periods and respective costs of conceived short-term plans is going to be shown.
A Comprehensive Geomechanical Study to Understand Drilling Challenges in the Manifa Field Offshore, Saudi Arabia
Authors: Ahmed Mujahed , Al-Shehri Hisham A. , Haidary Saleh A. , Povstyanova Magdalena 
Published: July 2016

Abstract
Saudi Aramco has been producing from the Manifa offshore field in the Arabian Gulf since 2011. By drilling mainly lateral wells, Saudi Aramco has targeted the main reservoir that belongs to the early Jurassic period. The pay zone is overlaid with weaker interbedded sand/shale formations and carbonate formations of the upper and lower cretaceous period.
The main challenges that were encountered while drilling these wells included total/partial mud losses and severe wellbore instability-related issues across the weaker formations overlaying the reservoir section (pay zone). An advanced geomechanical study was crucial for understanding the nature of the existing problems faced during drilling and applying the study's findings for drilling future extended reach (ERD) wells successfully.
A comprehensive geomechanical study of the field was conducted by constructing a calibrated post-drill 1-D Mechanical Earth Model (1D-MEM) for selected vertical wells. The study helped in providing reliable rock mechanical properties and fracture gradients across the problematic formations, a lack of which was a limiting factor in understanding the nature of the problems while drilling.
For the current study, an integrated workflow was implemented mainly to perform a root cause analysis of mud losses and to define well inclination (deviation) limits to drill through the problematic formations to minimize wellbore instability-related issues. Open hole log data was used to construct the 1D-MEMs. The developed models were further calibrated using all the available data (drilling observations, results of well testing, core mechanical testing, etc.). Image data was also analyzed to capture the presence of fractures/faults or related features along the wellbore.
Based on the analysis results, it was concluded that the mud losses in the overlaid carbonate formations were attributed to the presence of localized open natural fractures or caverns, or vugs. It was also concluded that most of the wellbore instability-related issues (hole pack-offs, stuck pipe incidents, etc.) occurred due to insufficient drilling mud weights that were not able to support the rock on the wellbore wall. The present study helped in better characterization of the problematic formations and also provided useful information for planning future extended reach (ERD) wells. Some of the provided recommendations included acquisition of micro resistivity image logs (to identify nature of fracture), implementation of real-time geomechanics, and optimization of mud rheology, mud weight program, and casing design.
Prediction and Management of Scale and Corrosion in a Harsh Operating Environment: Challenges and Innovative Solutions
Authors: AlGhazal Mohammed A. , AlKhowaildi Mustafa A. , Al-Driweesh Saad 
Published: July 2016

Abstract
Prediction of scale and corrosion in the oil and gas industry provides a valuable mean to address some of the most pressing challenges in field operations. Based on scale and corrosion tendency tests, a custom-built well integrity program can promote safer and more environmentally friendly production operations.
This paper presents practical techniques to predict potential scale and corrosion issues in a sour gas-producing field, and discusses control methods. The focus of this study is on the high pressure, high temperature deep horizontal wells that have been intensively acid fractured for economic production of tight gas. Scale precipitation is anticipated by geochemical analysis of produced water, including water hardness, limiting factor ion and stability index. Corrosion tendency is evaluated using laboratory tests simulating the acid fracturing treatment conditions.
Suspected scale and corrosion can be managed by applying a set of mitigating techniques, including selection and manufacturing of downhole completion equipment tubulars and accessories, acidizing treatment recipe and mixing guidelines, chemical inhibition selection and placement, as well as post-treatment over-flushing and flow back best practices. Innovative technological mitigating solutions include electro-kinetics technology, where more acid is consumed deeper inside the formation and a corrosion-sacrificial aluminum anode is incorporated. Also, the role of nano-sized additives in managing oxidizing reactions to enhance corrosion resistance is discussed. Field experiences have demonstrated that these strategies are effective in managing scale and corrosion, creating opportunities for asset reliability and operational excellence.
The novel technologies and operational guidelines discussed in this paper represent a holistic approach for operating companies to sustain tight gas production in spite of harsh scale-prone, corrosive operating conditions.
Business Intelligence Revolutionizes History Matching Process
Authors: Al-Ghamdi Reema , Al-Taiban Ali , Al-Zahrani Tareq , Al-Harbi Bader 
Published: July 2016

Abstract
One critical step towards building accurate reservoir simulation models is to efficiently assess the quality of the model's history match through identifying discrepancies between historical data and simulation model output to assess the history match quality. The role of Business Intelligence in history matching is crucial as it easily helps simulation engineers mine and manipulate data, visualize plots, identify patterns and run statistical algorithms. The History Match Quality Check (HMQC) tool capitalizes on these techniques and provides the required procedures to perform qualitative and quantitative analysis for simulation results in an efficient manner.
The developed tool helps engineers graphically identify wells, or cluster of wells, with discrepancies in pressure and water-cut trend, and offer a wide range of flexibility to rank simulation runs according to history match quality. One of the main advantages of the tool is that it can load data from different database sources as it combines both historical data and simulation output in one platform, and guide engineers to perform necessary adjustments to achieve a better history match. The HMQC tool is a dashboard which provides several tabs primarily for the main history match parameters such as first water or breakthrough timing, last and water-cut deviation and pressure evolution. Moreover, it allows engineers to extract statistical information from the simulation runs for quality check purposes and examine how close the model represents the field/reservoir performance. The tool uses advanced statistical algorithms to estimate the simulated properties' trend based on well performance, including first water breakthrough, water-cut and pressure trend against historical data.
This paper explains the algorithms used in the HMQC tool that utilizes Business Intelligence data mining and visual analytics to enhance and streamline the history match process.
An Experimental Study of Interfacial Tension and Contact Angles of CO2/Brines/Surfactants/Oil Systems with Dolomite Rock
Authors: Mahboob Ahmad , Sultan Abdullah S. 
Published: July 2016

Abstract
In this work the effects of different parameters such as surfactant type, salinity, temperature, pressure and oil type have been studied experimentally in the presence of CO2 at 30°C and pressures as high as 5000 psi for changes in interfacial tension and wettability with dolomite rock.
In the 1st step, IFT of four multicomponent brines of different salinities were compared and the brine showing lowest IFT with CO2 was used in the 2nd step for comparison of three different brine-surfactant solutions (BSS). The BSS with lowest IFT was then used to study the IFT behavior of three different oils with CO2. Last step consists of contact angle(CA) measurements of oil with dolomite rock in the presence of CO2 and BSS. Brines are multicomponent with salinities ranging from 8,500 to 67,000 ppm. Comparison of surfactants was among solutions of an alcohol-propoxysulfate surfactant, a viscoelastic surfactant and a fluorosurfactant.
IFT of brines increase with increase in salinity and temperature and decreases with increase in pressure. This is due to solubility of CO2 in brine. Out of the three surfactants, most soluble solution is a fluorosurfactant and gives ultra-low IFT with CO2. This BSS of florosurfactant when used with oil, forms pressure-sensitive microemulsions in CO2 causing the IFT of the oil to decrease. CA of oils with dolomite rock increase with pressure in the presence of fluorosurfactant and CO2.
In the literature, comparison of IFTs of different surfactants in CO2-Brine systems, Brine-Oil systems, Surfactant-CO2 systems, and surfactant-oil systems have been reported but this work reports on all CO2/Brine/Surfactant/Oil/Dolomite co-existing which can help in planning a Surfactant-Alternating-Gas(SAG) or Water-Alternating-Gas(WAG) process more accurately.