bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation and Optimization of Polymer Enhanced CO2 Foam Stability and Apparent Viscosity
Authors: Ahmed Shehzad , Elraies Khaled Abdalla , Hashmet Muhammad Rehan , Bt Mohd Shaifan Siti Rohaida , Hsia Ivy Chai , Bahrim Ridhwan Zhafri 
Published: June 2017

Abstract
Polymer enhanced foam (PEF) provides an additional strength over conventional CO2 foams for mobilizing oil from the unswept low permeable oil rich zones during an enhanced oil recovery process. The efficiency of the process depends on two major factors i.e. stability and apparent viscosity of PEF. In this study, an experimental investigation of apparent viscosity and stability of polymer enhanced CO2 foam is presented with an objective to assess the polymer performance and to identify the best performing polymer under reservoir conditions of 1500 psi and 80 °C.
For this purpose, conventional standard hydrolyzed polymacrylamide (HPAM) polymers and an associative polymer i.e. Superpusher P329 were used in combination with a widely used foamer i.e. alpha olefin sulfonate (AOS) and a foam stabilizer i.e. betaine. Foam stability tests were conducted in the presence of crude oil using FoamScan. Whereas for foam rheological study, a high pressure high temperature Foam Rheometer was utilized and the foam was sheared over the range of 10 to 500 sec−1 inside the recirculating loop.
As compared to other HPAMs, an associative polymer i.e. Superpusher P329 significantly amplified foam longevity and provided a more prolonged liquid drainage. A shear thinning behavior was observed for the entire range of shear rate tested and for all the tested foam. HPAMs were found ineffective in improving foam apparent viscosity and the viscosities obtained were found equivalent to that to polymer free foam. Superpusher P329 showed interesting combination with AOS and significant viscosity enhancement has been reported in this paper.
This research concluded that Superpusher P329 has the ability to generate strong foam and it is a potiential candidate for mobility control during polymer enhanced CO2 foam flooding process. Keywords: Polymer Enhanced Foam, foam stability, apparent viscosity; CO2 foam.
Effective Solutions for Cementing Shallow Hazards in Saudi Arabian Fields
Authors: Bazuhair Mohammed , Shine Jr Joseph M , Al-Mutahr Ammar , Abdurrahman Riefky , Shafqat Ali , Mojbel Mohammed 
Published: June 2017

Abstract
Shallow hazard migration post-cementing is a well-known and costly problem worldwide. It is extremely difficult to fix once it has occurred since limited remedial options are available with marginal success rates. Its causes are easy to understand yet it needs careful planning to prevent it. Post-cementing shallow water flow and gas migration may occur due to several collective causes such as poor fluid displacement efficiencies, losses prior/post or during cement placement, and/or underperforming slurry properties.
Previously proposed solutions focus only on one of these challenges with various success rate depending on well conditions. Addressing all these challenges together is essential for successful prevention. Due to the nature of these wells containing the high probability of flow from these shallow hazards, the clearances between pore and fracture pressures are narrow. This makes the common mud removal approach of displacement mechanics challenging. It also requires a delicate balance between maintaining sufficient hydrostatic to remain above the pore pressure of the flow zone and losing to the weak formations. Independent of these boundary conditions, the slurry needs to have a given set of performance properties to prevent any influx into the annulus.
This paper discuss the successful implementation of cementing solutions and control measures used to prevent shallow hazards migration in Saudi Arabia. This manuscript will discuss the field implementation and operations documenting the step changes success.
A Novel Acid Transport Model with Robust Finite Element Discretization
Authors: Alhubail Mustafa M. , Misra Anil , Barati Reza 
Published: June 2017

Abstract
The purpose of designing an acid fracturing model is to examine the two factors that measure the effectiveness of the acid fracturing treatment. The two factors are the acid penetration distance and the fracture conductivity after closure stress is reached.
The acid fracturing model is designed by coupling a fracture propagation model and an acid transport model. The advanced fracture propagation models are developed numerically by the finite element method (FEM,) or the extended finite element method (XFEM.) However, the acid transport models that are reported in the literature are developed using the finite difference method (FDM.) The finite element method is a more stable and accurate technique to model the complex system of the acid transport along with fracture mechanics and heat transfer than FDM. Furthermore, FEM is a more powerful and suitable technique for meshing sophisticated geometries such as fractures. Thus, an acid transport model has been developed numerically using FEM.
The objective of developing this FEM model is to eliminate the need of using different mapping and coordinate transformation techniques for the fracture propagation model and the acid transport model; hence, diminishing the inaccuracy when meshing the geometry.
The developed FEM model has been validated against analytical and numerical models, and it has been verified that the algorithm is stable and robust. The developed model predicts accurate velocity and temperature profiles. In addition, the model can handle acids with non-Newtonian flow behavior at a specific acid viscosity and acid dissolving power. It has been found that acids with shear thinning flow behavior yields shorter acid penetration distance compared to acids that are behaving as a Newtonian fluid. Furthermore, the effect of wormholes on the acid distribution has been studied, and it has been found that high injection rates result in deeper wormholes.
Revised Experimental Approaches To Address Shale Drilling Challenges
Authors: Al-Arfaj Mohammed K. , Amanullah Md , Zaidi Syed , Sultan Abdullah S. , Abu-Khamsin Sidqi 
Published: June 2017

Abstract
Shale drilling problems are major sources of non-productive time in drilling operations. The use of water-based drilling fluids to drill shale formations can cause wellbore stability problems such as swelling, dispersion and heaving as a result of the reaction of water with clay minerals. Consequently, wellbore instability problems can be triggered and stuck pipe problems can be encountered due to tight spots or higher solids loading in the wellbore. Therefore, it is essential to have the required techniques to assess the shale samples and their adsorption and swelling potential in order to be proactive and mitigate the scope of shale drilling problems. Initial moisture content is one of the factors controlling the swelling behaviour of shales. Correlating the ultimate swelling percentage to moisture content and other parameters can help in predicting the swelling potential and mitigating any associated problems. It was found that swelling potential increases for shale/clay samples with higher moisture content. Furthermore, evaluation of the long-term inhibition potential of shale inhibitors is necessary to mitigate time dependent borehole instability problems. Due to the presence of some unique geological conditions as in the case of a loss circulation zone overlaid with a shale formation, sometimes there is a need to replace a high cost inhibitive mud with a low cost non-inhibitive mud to drill the next formation. If the original inhibition provided by the inhibitive drilling fluid to the shale rock does not last long enough to drill the loss circulation zone, the previously drilled shale formation starts reacting again with the non-inhibitive drilling fluid leading to various drilling problems. Hence, there is a need for isolation of the reactive shale zone by a casing string before drilling ahead. Inhibitive muds with long-term inhibition potential may eliminate the need of a protective casing for the previously drilled shale formation. Two shale inhibitors were tested: potassium chloride and polyamins. The results showed the superior performance of the polyamines as long-term shale inhibitors compared to potassium chloride especially with shale samples of high kaolinite content.
Effect of Mobility and Convection-Dominated Flow on Evaluation of Reservoir Dynamic Performance by Fast Marching Method
Authors: Al-Qasim Abdulaziz , Kelkar Mohan 
Published: June 2017

Abstract
The determination of optimum well locations and number of wells needed during green field development always comes with unprecedented challenges because of the geological uncertainty, and the non-linear relationship between the input and output variables associated with real reservoirs. These variables are key sources affecting the viability and validity of the results.
Reservoir simulation is one of the least uncertain and most reliable prediction tools for dynamic performance of any reservoir. As field development progresses, more information becomes available, enabling us to continually update and, if needed, correct the reservoir description. The simulator can then be used to perform a variety of exercises or scenarios, with the goal of optimizing field development and operation strategies. Optimizing well numbers or locations under such geological uncertainty is achieved by using a reservoir simulator under several geological realizations, and these require multiple reservoir simulations to estimate the field performance for a given well configuration at a given location.
Using reservoir simulation becomes impractical when dealing with real field cases incorporating multimillion cells because of the associated CPU demand constraints (Bouzarkouna et al., 2012). For instance, to determine the optimum well locations in a giant field that will result in the most efficient production rate scenario, one requires a large number of simulation runs for different realizations and well configurations. A large amount of runs is technically difficult to achieve even if we have access to super computers.
The Fast Marching Method (FMM), which is based on solution of Eikonal equation, can be used to find the optimum well locations in a green oil field by tracking the pressure distribution in the reservoir. The FMM will enable us to calculate the radius of investigation or pressure front as a function of time without running any simulation and with a high degree of accuracy under primary depletion conditions.
The main purpose of this paper is to study the effect of mobility on FMM and extend the investigation of its validity to include two phase-flow and convection-dominated flow and evaluate the ability of the methodology to predict the dynamic performance of the reservoir during pseudo-steady state flow regime.
Reservoir Description Insights from an Inter-well Chemical Tracer Test
Authors: Sanni Modiu , Abbad Mohammad , Kokal Sunil , Ali Razally , Zefzafy Ibrahim , Hartvig Sven , Huseby Olaf 
Published: June 2017

Abstract
Tracer technology has evolved significantly over the years and is being increasingly used as one of the effective tools in the reservoir monitoring and surveillance toolbox in the oil and gas industry. Tracer surveys, conducted either as inter-well tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations.
As part of the comprehensive monitoring and surveillance program for an IOR injection pilot project in a Jurassic age reservoir, an inter-well chemical test (IWCTT) was designed and implemented to investigate reservoir connectivity between injector and producer well pairs, water breakthrough times ("time of flight"), and possible inter-well fluid saturations. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in the four "paired" up-dip producers.
In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. A detailed analyses of the exit age distribution and residence time distribution (RTD) curves showed two peaks for three of the injector-producer pairs and a single peak for the last pair. These were reflective of some apparent reservoir heterogeneities that were not anticipated at the beginning of the pilot.
This paper reviews the complete design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the field. This has led to better reservoir description and an improved dynamic simulation model.
Designing and Validating 2D Reservoir Models
Authors: Thompson Troy , Vogt Jay , Zaretskiy Yan 
Published: June 2017

Abstract
2D Conformal Modeling (2DCM) is a ground-breaking technique for building and maintaining 2D structural frameworks, especially with the existence of high-angle horizontal wells. 2DCM is proposed as the standard tool for accurately and efficiently interpreting horizontal wells and constructing frameworks. The 2DCM workflow has been developed and refined over the past 10 years using thousands of horizontal wells in active development areas across a wide region. In addition to accurately representing the geological observations along the entire horizontal well, it is a very efficient method that enables interpreters to update their models while drilling and to accurately incorporate intra-formational observations. This enables truly "living" models that serve as the front end to reservoir and fluid modeling, forming the basis of a Live Earth Model.
Unconfined Compressive Strength Prediction from Petrophysical Properties and Elemental Spectroscopy Using Support-Vector Regression
Authors: Negara Ardiansyah , Ali Syed , AlDhamen Ali , Kesserwan Hasan , Jin Guodong 
Published: June 2017

Abstract
Unconfined compressive strength (UCS) of rock is a key parameter in drilling and stimulation of oil and gas wells such as wellbore stability and fracturing operations. Better estimates of UCS could increase the efficiency of drilling and stimulation operations. Current techniques for UCS determination either rely on laboratory measurements or empirical relationships using well logs. The laboratory measurements, although more reliable, are expensive and time-consuming. On the other hand, the empirical relations derived from core data and well logs are very unique because they are developed for a specific rock type; hence has limited applications. This paper presents a data-driven model for UCS prediction from petrophysical properties and elemental spectroscopy using artificial intelligent technique, namely support-vector regression (SVR).
Elemental spectroscopy, density, porosity, and UCS data presented in this paper are based on various geological formations. UCS is determined by the uniaxial compression test in the laboratory, while elemental spectroscopy was obtained from X-ray fluorescence (XRF) analysis. We first use SVR to establish a correlation between elemental spectroscopy, density, and porosity with UCS. We separate these data into two categories: training and testing data. Training data is used to train SVR and establishes the UCS prediction model. The model will generate UCS prediction using testing data and compared with the laboratory-measured UCS.
In total, 21 cases were run with different combination of input parameters. Good agreement was observed between the SVR-predicted UCS and the laboratory measurement. Two quantitative measures for estimation accuracy are calculated and examined including the coefficient of determination and the mean absolute percentage error. Considering limited number of available data used in this study, the SVR-predicted UCS produces very good coefficient of determination and small error. The results also demonstrate the significant influence of elemental spectroscopy on the UCS prediction because elements determine grain density, which contributes to the rock strength. This emphasizes the advantage of incorporating elemental spectroscopy, together with other petrophysical properties, for UCS prediction. The favorable results in this study demonstrate the promising capability of SVR to build a UCS-prediction model based on elemental spectroscopy and petrophysical properties. Further application of SVR can be adapted to predict UCS directly from mineralogy logs and conventional well logs.
Fit for Purpose Design of High Performance Water Base Mud Successfully Replaced Oil Base Mud
Authors: Ferras Abdelkader , Al Obeidany Rashid , Qassabi Nabhan , AL Aghbari Salim , Abry Nadia , Benmesbah Mohamed Oukil , Benmahiddi Samir , Radwan Mohamed , Van Der Werff Niels , Samiee Rady Abdel , Mahrooqi Mohammed , Chibani Zied 
Published: June 2017

Abstract
Despite the associated waste management cost to comply with the international standards, Oil Base Mud (OBM) remains the drilling fluid of choice to drill trouble prone formations in PDO LLC, Oman drilling operations mainly through the formations of Fiqa Sharji, Nahr Umr, Khuf and Gharif in different fields of Oman. Low Toxicity Oil Base Mud (LTOBM) is exhibiting excellent well bore stability due to oil wet property, however, its high cost resulting from low aromatic base oil and associated waste management to comply with the international standards and local environmental regulations provided the impetus to conduct a feasibility study to identify an environmentally friendly and cost effective drilling fluid without impairing drilling performance. The evolvement of High Performance Water Base Mud (HPWBM) technology helped to identify a fit for purpose drilling fluid capable to deliver near OBM drilling performance with cost effective environmental compliance with local regulations.
The following tests were carried out on different cuttings samples collected from the aforementioned formations when exposed to different drilling fluids formulations:
Cation Exchange Capacity (CEC). Linear Swelling. Shale recovery. Accretion.
As a result of the intensive laboratory work, an appropriate HPWBM system was selected for each formation and each field. The first fields' trials concluded promising results with 100 % success rate on vertical wells and 50 % success rate on horizontal wells. HPWBM drilling performance was competing with OBM with significant cost reduction of 33-70 %. Further benefits, such as better zonal isolation achieved through better cement bonding to both formation and casing is worth considering.
More importantly, two wells drilled by this HPWBM were initially planned to be water injector wells and ended by being converted to oil producers after positive logging results. This is an important field proven feature for a reservoir friendly system.
This paper details the engineering works performed at PDO laboratory on testing the shaly cuttings behavior against different drilling fluids and at the field trials describing the best practices.
Introducing a Big Data System for Maintaining Well Data Quality and Integrity in a World of Heterogeneous Environment
Authors: Bin Mahfoodh Abdulelah , Ibrahim Mohamad , Hawi Maan , Hakami Khalid 
Published: June 2017

Abstract
Oil and gas industry is a data-driven industry as it depends massively on information technology. According to internal statistics, the amount of data coming from upstream alone is doubling every two years. This data arrives through a wide variety of vendors’ sources and is handled by various applications’ repositories. Well data, in specific, is a key asset for such industry throughout the process lifetime from early exploration to production. In practice, companies often tend to create their own well data master repositories that are poorly synchronized between each other and with other databases. This results into well data residing in silos databases with no commonly defined standard. Often, there is little mechanism to cross-validate well data quality across various sources. Thus, maintaining high quality level of definitive versions of well data is a critical activity to any firm's data management strategy.
Recently, Big Data technologies have evolved to quickly fetch and analyze large volumes of data that can substantially lead to an improved data quality at reasonable time. In this paper, a novel system is presented to preserve high level of well data quality in a heterogeneous environment. This system utilizes Apache Spark as a main framework for distributed processing and a mid-tier software as a data integration layer. Through a set of defined mapping rules, the system will compare data from multiple databases against the database that hosts the organizational verified data. It is typical for oil and gas companies to dedicate one master database containing the corporate standard well data. So, this database will be used as a source for comparison against well data residing in project repositories. Moreover, the system extends its functionality to cover well sub data types such as headers, check shots, deviation surveys, and picks. The final output is a data quality report that helps in making strategic decisions.