bluuebunny/crossref_metadata_2025_split huggingface dataset:
Completion Evaluation to Stimulate and Test Tight Laminated Sands
Authors: Al-Ameer Musab N. , Uche Ifeanyi , Camacho Diego , Al-Otaibi Nashi M. 
Published: October 2018

Abstract
Tight gas sands worldwide hold significant gas reserves and a vast majority of this low permeability rocks are sandstones. Stimulating tight laminated sands pose a great challenge in terms of completion and stimulation practices. Laminated sands have often been bypassed due to the high cost of hydraulic fracturing and the need to design a fit for purpose completion system. Therefore, it is important to develop an approach to address this and also get better understanding on the impact of stimulation and completion strategy for tight laminated gas sands in Saudi Arabia. High pressure is often required to break down the formation and propagate hydraulic fracturing treatment. This paper describes case histories and solutions for better completion designs in order to stimulate laminated tight gas sands successfully. With the demand to optimize Expected Ultimate Recovery (EUR), tight laminated sands have become an interesting target for unconventional gas resources with some intervals with potential based on logs, but faces challenges stimulating due to completion design. This paper compares the results of wells that were completed in the area, reviewing detailed stimulation and completion design and providing recommendations for future completion.
History Matching a Gas Reservoir Using Ensemble Based Methods
Authors: Ravanelli Fabio , Pamukcu Yusuf 
Published: October 2018

Abstract
Ensemble smoother with multiple data assimilation (ES-MDA) is an advanced assisted history matching technique that is capable of reducing the utilization of existing computational resources while improving the quality of the simulation models by preserving the geological consistency of the model during the history matching process.
The subject reservoir in this paper was modeled using an object based modeling approach with appropriate object size distribution and connectivity. This approach generated a stacked dunes-interdunes complex that models the objects as isolated geobodies as observed in dynamic data.
A set of geological realizations were generated by encompassing to capture the uncertainty in sand geobodies distribution, permeability variation and flow barriers. These geological realizations were history matched using the ES-MDA with covariance localization using the state of art in-house reservoir simulator, GigaPOWERS.
The final model attained an excellent history matching quality and predictability capacity. A comparison between the manual history matching results and the ES-MDA is presented to illustrate the value and the impact of the methodology in reservoir simulation studies. The results obtained strongly encourage the further utilization of the presented methodology for history matching.
Investigation of Heavy Oil Recovery Using Sequential Viscoelastic Surfactant and Chelating Agent Solutions as EOR Fluid for HTHS Conditions Carbonate Reservoirs
Authors: Janjua Aneeq Nasir , Sultan Abdullah S. , Kamal Muhammad Shahzad 
Published: October 2018

Abstract
Viscoelastic surfactants are known to be the best for chemical EOR (cEOR) applications as compared to polymers and surfactants because of its dual capability of reducing the oil/water interfacial tension (IFT) and improving the sweep efficiency. Carbonate reservoirs become most challenging cEOR targets when they are characterized as high temperature and high salinity (HTHS). In this work, a systematic study is carried out to design a formulation using a sequential viscoelastic surfactant (VES) and chelating agent (CA) solutions for recovering heavy oil from carbonate reservoirs.
The objective of this work is to investigate the chemical formulations of viscoelastic surfactant and chelating agent with heavy reservoir oil of 17°API and 234,189 ppm salinity formation brine. Thermogravimetric analysis (TGA), nuclear magnetic resonance (NMR) and fourier transform infrared (FTIR) are used to evaluate the thermal stability of VES. Encouraging results with TGA demonstrate that VES is thermally stable and show high resistance to temperatures up to 250°C. NMR and FTIR results also show good long-term thermal stability when aged for 30 days. Ultra-low oil/water interfacial tension measurements are recorded using spinning drop tensiometer and lie in the range of 10−1 to 10−2 m-Nm−1. Effects of concentration, time and temperature on IFT are evaluated. It is also noted that ultralow IFT is obtained at 50°C and 80°C. Static adsorption has been evaluated by shaking the powdered core samples with VES at two different temperatures for 24 hours. Concentration measurements are performed using total organic carbon (TOC) analysis. Static adsorption results give less adsorption when we have higher temperatures compared to lower temperatures. Coreflooding experiments are designed with VES and VES-CA at 90°C using carbonate core samples to determine the additional oil recovery. Overall oil recovery factor with VES and VES-CA of 47% is calculated when plotted against injected pore volumes. Pressure drop profile, oil rate and water rate are also determined, and their graphs are presented with injected pore volumes.
This study provides an integrated approach of evaluation and application of viscoelastic surfactant and chelating agent solutions for chemical EOR in heavy oil reservoirs. Thermal stability, ultralow IFT's, adsorption and additional oil recovery obtained with viscoelastic surfactant and chelating agent show that they are excellent additives that can be used in cEOR for high salinity and high temperature conditions. They are also very useful when we have heavy crude oil and where IFT reduction is required to mobilize the oil and improve the sweep efficiency of the reservoir.
New Approach to Predict Fracture Pressure Using Functional Networks
Authors: Abdulmalek Ahmed S , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Mahmoud Mohammed , Ali Abdulwahab Z. , Mohamed I. M. 
Published: October 2018

Abstract
Fracture pressure plays a key role in designing the mud weight and the cement slurry density in the drilling operation. Knowing the fracture pressure will eliminate many problems such as loss of circulation and hence reduce the time and the cost of the drilling operation. Many empirical models reported in the literature were used to calculate the fracture pressure based on different parameters. Most of these models used only formation and rock properties to estimate fracture pressure. Other models predicted the fracture pressure based on log data using a few real field data. Artificial intelligence techniques once optimized can be used to predict the fracture pressure with high accuracy.
The objective of this research is to predict the fracture pressure based only on surface drilling parameters which are easy to get namely weight on bit (WOB), rotary speed (RPM), drilling torque (τ), rate of penetration (ROP), mud weight (MW) and formation pressure (Pf). More than 4700 real field data points are used to predict fracture pressure using Functional Networks (FN) which is a method of artificial intelligence (AI).
Functional Networks (FN) tool was compared with different empirical models. The result showed that FN methods outperformed all the fracture pressure equations by high margin (very high correlation coefficient (R) of 0.986 and a very low average absolute percentage error (AAPE) of 0.201). the developed technique will help the drilling engineers to design the cement slurry and determine the casing setting depth. In addition, the drilling engineers will be able to eliminate the common drilling problems such as loss of circulation.
Drilling and Enlarging Surface Pilot Holes in Hard Formations Utilizing Drill Bits, Save Time, Enhance Performance and Reduce HSE Risks
Authors: Atriby Kamal , Scagliarini Stefano , Alfaqhi Abdulqawi , Aljumah Ali , Sindi Albadr , AlGhofaili Saleh 
Published: October 2018

Abstract
In some oilfields, drilling surface big-size wellbores through hard formations yields low drilling performance. Moreover, in these environments, high Shock and Vibration (S&V) are generated causing premature failures of the drilling rig equipment and the drillstrings, increasing rig maintenance costs, Non-Productive Time (NPT), and the risk of loosen drilling rig equipment that could result in dropped (falling) objects and consequent potential injuries to the drilling crews. In these cases, it is envisaged to use the Kelly system for drilling to prevent damage to the Top Drive System (TDS) that however, leads to non-efficient operations and to an increase of Health Safety and Environmental (HSE) hazards in handling more connections (singles).
To improve efficiency, a pilot hole is drilled with a smaller drill bit to the section total depth using a performance downhole motor as the driving mechanism to deliver the required power, torque, and revolutions. The pilot hole is then enlarged to the required bigger-size borehole using a drill bit and, again, a downhole motor. The Bottom Hole Assemblies (BHAs) for both the pilot hole and the enlarged borehole, are designed and optimized to minimize BHAs' components handling, minimize S&V and to improve overall operational efficiency. To date, this technique has been successfully implemented in many wells in different drilling environments, improving the section drilling performance by 40-50%, and reducing both well time and drilling costs. Also, S&V diminished, with a consequent reduction of the HSE risks.
This paper highlights the engineering aspects of the pilot hole and hole-enlarging design and implementation, together with the results obtained.
Challenging Conventional Best Practices with an Updated Productive Drilling Solution
Authors: Al-Majed Alawi , Soh Azrin , Ali Anis , Farid Mazhar , Jallouli Mohamed Amine 
Published: October 2018

Abstract
Among the challenges facing an operator while drilling offshore in the Middle East are the 16-in. sections of wells where highrisk of losses and torque and drag limitations force the operator to be extremely conservative during the planning stage. Operator objectives for this particular interval normally call for mitigating any high-potential incidents, which is driven by the past experiences as well as decades of old best practices. The approach used in the past has been to drill with a positive-displacement mud motor and weighted mud until losses are experienced, and then switch to mudcap drilling to maintain hydrostatic while drilling. The positive displacement mud motor efficiency is excellent in lower inclination wells but deteriorates once the inclination exceeds 30n, leading to significantly lower penetration rates and extending the openhole wellbore exposure time. This prolonged openhole time exposes the bottomhole assembly and wellbore to the same risks the operator has always attempted to avoid.
A service provider evaluated the drilling method with the objective of reducing the drilling time and drilling risks. Drawing from offset well experiences and the conditions of successful operations, a motorized rotary steerable system (RSS) was proposed to the operator. Time and cost analysis were performed, showing that improved hydraulics and drilling dynamics would result in significanttime savings and should be compounded as the 16-in sections are drilled in batches of up to seven wells.
The operator implemented the recommended BHA and parameter design for the remaining seven wells, resulting in up to a 120% increase in the average rate of penetration by the motorized RSS over conventional positive displacement motors. The accompanying benefits to the operator included increased hole cleaning capacity, torque and drag reduction in tripping times, and reduced risk exposure in the 16-in. sections.
The results obtained with the updated design demonstrated that in the current challenging energy market environment, using proven technologies to challenge decades of best practices can bring significant benefits to the well construction and enhance the performance benchmarks for future wells.
Predicting Rate of Penetration Using Artificial Intelligence Techniques
Authors: Al-AbdulJabbar Ahmad , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez 
Published: October 2018

Abstract
Rate of Penetration referrers to the speed of breaking the rock under the bit. It measures the speed or the progress of the bit when it drills the formation. It has been reported in the industry that high percentage of the well budget is spent on the drilling phase, thus many drilling operators pay close attention to this factor and try to optimize it as much as possible. However, it is very challenging to capture the effect of each individual parameter since most of them are interconnected, and changing one parameter affects the other. As a result, many companies maintain a data for the drilling performance per field and set certain benchmarks to gauge the speed of any newly drilled well. To date, no solid or reliable model exists because of the complexity of the drilling process, and one cannot capture every factor to predict the rate of penetration. Therefore, the utilization of artificial intelligence (AI) in the drilling applications will be a game changer since most of the unknown parameters are accounted for during the modeling or training process.
The objective of this paper is to develop a rate of penetration model using artificial neural network (ANN) with the least possible number of inputs. Actual field data of more than 4,500 data points were used to build the model. The inputs were pumping rate, weight on bit, rotation speed, torque, stand pipe pressure and unconfined compressive strength. Well-A was used to train and test the model with 70/30 data ratio. Then two unseen data which are well-B and well-C were used to test the model. ANN was used in this study, with many sensitivity analyses to achieve the best combination of parameters.
The obtained results showed that ANN can be used effectively to predict the rate of penetration with average correlation coefficient of 0.94 and average absolute percentage error of 8.6%, which shows 22% improvement over the current published methods. The best ANN model was achieved using 1 layer, 12 neurons and a linear transfer function. The developed ANN-ROP model proved to be successful using only six inputs and having a total of two wells with unseen data.
Linking Geochemical and Mechanical Properties of Rock Samples Using New Non-Destructive Techniques
Authors: Hussain Maaruf , Amao AbdulJamiu , Jin Guodong , Al-Ramadan Khalid 
Published: October 2018

Abstract
Geochemical analysis of rocks is fundamental to the understanding of geology and earth sciences. X-ray dispersive spectrometry and other automated techniques are increasingly being used to determined and quantify the abundances of the major, trace elements and other rock properties. This study utilized a combination of dispersive spectrometric techniques (MicroXRF) and impulse rebound hammer method to establish links between geochemical and mechanical properties of rocks through a non-destructive method. MicroXRF has high resolution and can detect trace elements within the parts per billion range. The micro-rebound hammer was used to generate a reduced Young's modulus (E*), which gives a measure of the rock strength with negligible impact on the rock itself.
In order to explore, visualize and understand the dataset generated, principal component analysis (PCA) was applied to emphasize variation and bring out strong patterns in the dataset. The first two dimensions of PCA express 57.09% of the total dataset inertia; that means that 57.09% total variability in the data is explained by the planes/dimensions. The first dimension, which showed a strong positive correlation to clay forming minerals and rock strength, was tentatively identified as the clay gradient. The second dimension describes diagenetic alteration processes responsible for the enrichment of elements such as Ni, Mo etc. Further, a positive correlation was established between E* and four elements Cobalt (Co), Strontium (Sr), Titanium (Ti), and Zircon (Zr). Remarkably, Silicon (Si) had a negative correlation with all elements but positive correlation with porosity and permeability. We therefore identified Co, Ti, Sr, and Zr as proxy for the determination of rock strength specific for studied samples and proposed a workflow based on our sequences of analysis and interpretation. Furthermore, we identified four chemo-mechanical facies through hierarchical clustering of the product of the PCA.
This presented methodology could be specifically useful for geomechanical characterization of rocks; a key requirement needed for in-situ stresses estimation, wellbore stability analysis, reservoir stimulation and compaction, pore pressure prediction, and more importantly for characterizing drill cuttings where size and time are limiting. Drilling operations require constantly evolving cost effective and time efficient techniques, the proposed workflow will serve these purposes i.e. rapid determination of elemental composition (microxrf) coupled with E*will give a reliable proxy for rock strength. The technique can be applied to, drill cuttings, slabs and whole core directly without prior sample preparation.
Removing Dispersed and Dissolved Hydrocarbons From Water Using Adsorption Media Systems With Multiple Regeneration Processes
Authors: Smathers Caleb , Jackson Tommie , Buckwald Scott , Gonzalo Raul , McPherson Ryan 
Published: October 2018

Abstract
Clean water is a precious resource in the world. For decades, nations and companies have focused on delivering contaminant-free clean water as a byproduct of industrial processes. ProSep's Osorb Media Systems (OMS) deliver oil free water from the oil and gas industry's most challenging onshore and offshore water treatment applications. OMS not only remove challenging hydrocarbon contaminants from produced water, they do so with high efficiency over a long media life. Osorb uses a physical adsorption mechanism to remove hydrocarbons from water. Additionally, the unique structure of the media enables the adsorption isotherm to be reversed thus releasing the captured hydrocarbons from the media. The regeneration process is completed using a combination of physical and/or thermal processes that enable hydrocarbon recovery.
Two pilot tests and one field test were completed demonstrating the OMS treatment and regeneration capabilities for both dispersed and dissolved oil removal. Three different regeneration methods were found to be effective. The first pilot test demonstrated over 99% removal of dissolved hydrocarbons throughout 28 water treatment and steam regeneration cycles. A second pilot test demonstrated a 2.6:1 (wt:wt) recovery of crude oil from Osorb while maintaining efficient water treatment. The field test had eight regenerations (five with steam and three with natural gas) completed and the media maintained 98% removal efficiency and averaged &lt;1 mg/L of dispersed oil in the effluent water.
OMS provide a proven technical solution along with the economic feasibility to treat dissolved and dispersed hydrocarbons from water which have proven challenging for the oil and gas industry.
A Novel Polymer Nanocomposite Graphene Based Gel for High Temperature Water Shutoff Applications
Authors: Almoshin Ayman M. , Alsharaeh Edreese , Fathima Arshia , Bataweel Mohammed 
Published: October 2018

Abstract
This study suggests a polymer nanocomposite gel system that can effectively be used as water shutoff material for high temperature reservoirs. Based on nanotechnology, a novel cost effective and ecofriendly polymer gel formulation is presented. This newly developed material extends the temperature limitations for high temperature reservoirs.
In particular, this paper reports an innovative graphene-based zirconium oxide nanocomposite as a crosslinker for water shutoff utilizing polyacrylamide polymer and its derivatives. Thermogravimetric analysis (TGA) and X-ray diffraction (XRD) were utilized to characterize the fabricated gel samples. The microstructure of the polymer nanocomposite gel was analyzed using scanning electron microscopy (SEM). The new developed formulation of the nanocomposite gel fluid was evaluated by rheometer tests at different ranges of pH (temperature up to 330°F) to study the gelation behavior and performance of the system for water shutoff application. Furthermore, the newly developed fluid system was injected into core samples to evaluate the ability of the gel to resist extrusion and determine the strength of the treatment under reservoir conditions. The polymer nanocomposite gel showed surprising mechanical properties with extraordinary thermal properties at elevated temperature. The TGA result revealed a remarkable shift of three main decomposition regimes at high temperatures, which confirms the enhancement of thermal stability of the synthesized nanocomposites polymer gel. The XRD pattern of the polymer gel had peaks that confirm the existence of the graphene and zirconium oxide in the system. The SEM images showed that this new class of polymer gel has a homogeneously distributed 3D network microstructure. The small size of the gel grid pores made the network structure thermally stable and firmly locked water within the gel even under high temperatures. The addition of sodium carbonate could also elongate the gelation time from ~70min. to 104 min at high temprature (330°F). The core flooding results showed a significant drop in water production for the sandstone matrix core that had higher permeability before the treatment.
The developed nanocomposites polymer gel with enhanced mechanical and thermal stability can significantly reduce excess water production within high temperature reservoirs at lower costs than the currently available polymer gels.
Leveraging Supercritical CO2 to Rejuvenate Hydraulically Fractured Wells in Unconventional Reservoirs
Authors: Kurdi Mohammed , Veveakis Manolis , Poulet Thomas 
Published: October 2018

Abstract
It is not uncommon that wells drilled in shale reservoirs experience a large Initial Production (IP), followed by a significant drop in productivity a few months after hydraulic fracturing, leading to a reduced Estimated Ultimate Recovery (EUR), with primary recovery factors rarely exceeding 15%. This drop in productivity constrains the economics of wells, and entails operators to drill and stimulate more wells to retain a production rate target. Recently, refracturing has emerged as a means to increase the productivity of these wells. Numerous well interventions are required to isolate and perforate new zones in addition to the increased costs associated with fracturing fluids and proppant requirements.
This paper investigates the physics of using supercritical CO2 as a secondary recovery method to rejuvenate hydraulically fractured wells in shale reservoirs. Under highly in-situ compressive stresses, diagenesis (fluid release) reactions provoke instabilities within the shale generating high porosity channels parallel to the minimum horizontal compressive stress. These channeling localization instabilities exist in ductile formations and are periodically interspersed in the shale's matrix. Induced hydraulic fractures intersect these channels, invoking pressure drawdown and drives production from these high velocity pillars. These channels close with well depletion, causing a sharp productivity decline. This paper predicts the critical fluid pressure above which pressure should be maintained by CO2 injection to prevent the channels from closing.
A computational model was developed for a shale play in Saudi Arabia as a case study. As the in-situ compressional stresses are high and its geologic setting is applicable, the critical fluid pressure is calculated. This paper aims to further the understanding of using CO2 as a secondary recovery technique and helps pave the road for a more sustainable future by sequestering CO2 into the ground and enhancing the EUR of shale oil and gas reservoirs.