bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management of the Change of Operation Classification Coding System for the Next Leap
Authors: Amer M. M. , Contreras W. B. , Canlas J. P. , AlShehri I. H. 
Published: October 2018

Abstract
National Oil Companies have always invested in and been dependent on information; gathering, managing, and utilizing data has now, more than ever, become more central to operational success. While the Drilling & Workover (D&WO) business is faced with retaining its capacity to do core operations, it is challenged to increase the rate of learning for drilling personnel.
Achieving these goals should be through a continuous process, which is data dependent. Data is only as valuable as the ability of engineers to extract meaning from it; meaning cannot be extracted without organizing, standardizing, and analyzing data effectively. Drilling data analysis is routinely performed in performance analyses/optimization; having a standard, consistent, yet flexible/scalable classification system is a must for this process.
Although drilling data has been available from the daily drilling reports and being utilized for performance analysis for long time, the process of performance analysis to extract knowledge and identify potential improvements has been hindered as a result of the limited variety and quality of the operation coding system previously in place. This paper is suggesting to move to a new coding system and will share how that change was managed successfully. The new system will be used to classify drilling operations more consistently, objectively, and comprehensively; and so a separate detailed lost time coding system was introduced. The normal operation codes were reviewed and cleansed, and comprehensive built-in quality control rules were developed and embedded in the system to allow guided operation classification and to make it easier for the end user.
A true challenge here was the management of this change, which impacted not only a huge volume of legacy data, about 10,000 wells, but also hundreds of end users with different business interests. Getting buy-in from different, and perhaps conflicted, stakeholders; migrating legacy data from the old structure to the new one; and training a massive number of end users were true challenges that had to be managed to make the change happen. In this paper, the authors would like to share their experience of managing this major change and how these different challenges were tackled.
Integrating Peng Robinson EOS with Association Term for Better Minimum Miscibility Pressure Estimation
Authors: Al-Kadem M. S. , Al-Mashhad A. S. , Al-Dabbous M. S. , Sultan A. S. 
Published: October 2018

Abstract
Minimum miscibility pressure (MMP) is a very critical parameter to design any enhanced oil recovery affiliated with carbon dioxide (CO2) gas injection methodology. MMP can be computationally estimated using the Peng Robinson Cubic Equation of State (PR-EOS). In this paper, an association term was incorporated into the equation to account for covalent bonds between oxygen and carbon atoms in a CO2 compound for accurate MMP estimation.
During the CO2 gas injection process, interactions between the oil multicomponent system and injected CO2 are in place where strong electrostatic force is exhibited between oxygen and carbon atoms. This attractive force cannot be neglected. Nevertheless, a Cubic Equation of State, such as Peng Robinson, accounts only for physical forces such as repulsion and attraction forces only. For this, an association term is introduced to account for electrostatic forces. Cubic plus Association EOS (CPA-EOS) was assimilated with Ahmed Tarek's methodology to estimate MMP rigorously in consideration of oil system and CO2 compositions.
MMP was estimated using both PR-EOS and CPA-EOS, and compared against the experimental value with a very minimal absolute error. Therefore, the results showed a close agreement between calculated and experimental MMP. The uncertainty was immensely reduced when utilizing CPA-EOS proposed by Ahmed Tarek for MMP estimation. Three correlations were applied to estimate MMP with a slightly high deviation from the experimental MMP values. This high error is due to the ignorance of the intermolecular forces exhibited between molecules among these correlations. It is worth mentioning that this proposed method is highly appreciating the intermolecular bonding exhibited in CO2 and hydrocarbon multicomponent mixture, which results in a very reliable and accurate estimation of MMP. In other words, integrating conventional EOS with the association term provides accurate estimation of MMP to ensure effective modeling of an enhanced oil recovery (EOR) design with CO2 injection.
Chemical Sealant Loss Circulation Materials for Fractured Formations: Right-Angle Viscosity Development with High Plugging Efficiency
Authors: Abdulrazzaq Waseem , AlBuraikan Reem , Savari Sharath , Whitfill Donald L. 
Published: October 2018

Abstract
Numerous lost circulation materials (LCMs) are sold in the global market to cure losses in highly fractured formations, but the success rate remains minimal. Lost circulation (LC) is a common challenge of global operators and service companies during either drilling or the oilwell construction phase of development and exploration. A new chemical-sealant-based LCM (CS-LCM) was developed to cure severe-to-total losses in highly fractured formations. The new CS-LCM is dispersed in a nonaqueous carrier fluid (NAF) and quickly forms a highly malleable viscous mass upon exposure to an aqueous reactant fluid and then sets harder under a wide range of temperatures.
Comprehensive and systematic tests were conducted on the new CS-LCM to determine the speed of the reaction at an optimized interval of time upon interaction with the reactant. Testing performed on the new CS-LCM included evaluating its flowability before and after the reaction and estimating the compressive strength. Additionally, the developed strength robustness of the CS-LCM was evaluated by its ability to withstand large differential pressures across extra-large holes (31 mm) in test media (simulating vugs in a formation).
The reaction rate of the CS-LCM showed measurable right-angle viscosity (RAV) development once the CS-LCM was preconditioned at a bottomhole circulation temperature (BHCT) and allowed to mix with preconditioned (at BHCT) reactant. A significant amount of compressive strength (&gt;500 psi) buildup was observed in less than 1 hour of reaction time, which sustained more than 1,000 psi differential pressure on large vugs. The fast increase in viscosity (i.e., RAV) and quick strength development are the result of fast-reacting chemical additives present in the mixture. Additionally, the resultant set CS-LCM was determined to be soluble in 15% hydrochloric (HCl) acid at ambient temperature; hence, it is a viable solution for a reservoir section.
The new CS-LCM was developed to mitigate severe-to-total losses in highly fractured formations by means of RAV development followed by rapid strength buildup in a short interval of time, thus helping prevent overdisplacement away from the wellbore, hence minimizing nonproductive time (NPT) and drilling mud losses.
Integrated Approach to Prevent and Mitigate Stuck Pipe in Interbedded Depleted and High Pressure Gas Reservoirs
Authors: Atriby Kamal 
Published: October 2018

Abstract
Stuck pipe is one of the main challenges in any drilling operation especially drilling horizontal or deviated wells through deep reservoirs. Stuck pipe occurs while drilling, logging, running casing and running lower completion especially the Multi-Stage Fracturing (MSF) completion string. This causes long non-productive time, limits the drilling performance and increases the well cost. An integrated approach is necessary to eliminate and reduce the stuck pipe occurrence and improve operation efficiency.
This integrated approach starts with the planning phase by evaluating the formations characteristics, pressure and stresses across the planned well, and creating the predrill Mechanical Earth Model (MEM) using offset wells information to calibrate it. This allows to anticipate the drilling conditions and the severity of the risk in each well. The drilling fluid and bridging materials are designed based on the formations characteristics, lithology, pore pressure and anticipated pore throat sizes using specific software packages to identify the optimum bridging plan. The drilling, logging, and the completion strings are designed based on the risk type and severity. The operational practices and operating envelope are set based on the downhole anticipated conditions, risk severity and type, hydraulics and hole cleaning simulations. Actual downhole conditions and a reviewed risk level are continuously monitored and fed back in the process: the operational practices, the drilling fluid properties, the bridging materials design and operating envelope are revised and optimized based on the actual wellbore conditions during execution to improve operational efficiency and reduce the stuck pipe risk. The post job evaluation is a crucial part of the process to analyze the efficiency of the implemented actions, to capture lessons learned, and revise and update the integrated approach for continuous improvement.
This paper describes the whole integrated approach process together with the results of the implementation carried out in several wells with different profiles and subsurface conditions. It also highlights the successes achieved in stuck pipe prevention and improved operational efficiency.
Newly Engineered Tapered Drillstring in Deep and Complex Gas Wells Saves Rig Time and Reduces Operational Risks
Authors: Atriby Kamal 
Published: October 2018

Abstract
Drilling deep reservoir sections requires long drillstring and, consequently, long tripping and handling times. The long and heavy drillstring generates high side forces across the casing especially in S-shape and J-type wells that could affect its integrity. The operating envelope is affected and results in limited operational efficiency. A fit for purpose tapered drillstring was designed with the objectives of enhancing the operating envelope, minimizing the forces and stresses applied to both the drillstring and the casing, reducing the handling time to improve operational efficiency.
This newly engineered tapered string consist of 4" and 5-1/2" drill pipes, optimum number and size of heavy weight drill pipes and drill collars, and fit for purpose driving and steering mechanism to be utilized in both the 8-3/8" and 5-7/8" hole sections. The design is based on torque and drag simulations, drillstring dynamics and hydraulic analysis together with the driving mechanism and drill bit designs, paramount to reduce shock and vibration.
This novel approach was implemented successfully in various well types saving an average of 1.5 days per well. It also reduced both the downhole circulating pressure fluctuations and the Equivalent Circulation Density (ECD) by providing bigger annular clearance thus having a positive impact on differential sticking risks, side forces, and torque and drag.
This paper describes the engineering design and modeling undertook and the successful implementation of the tapered drillstring in deep and complex gas wells.
ThruBit Logging Saves Time and Reduces Stuck Pipe Risk in Very Challenging Downhole Conditions
Authors: Atriby Kamal 
Published: October 2018

Abstract
Generally, highly deviated and horizontal wells, with challenging borehole conditions, are logged using the Tough Logging Conditions (TLC) technique, which allows the logging tools to be run pipe-conveyed utilizing the drill pipes. This method however, takes considerable time up to two days per run and has many inherent operational risks such as stuck pipe, long open hole exposure time and potentially, wellbore deterioration. Also, in case of an obstruction in the open hole or in the presence of a logging tools failure, the TLC logging assembly must be pulled out of hole and a conditioning trip may be required before continuing with the logging operations. The ThruBit logging technique eliminates and mitigates most of the TLC operational risks saving rig time.
At section Total Depth (TD) and before running casing or an open-hole lower completions such as a Multi-Stage Fracturing (MSF) string, the ThruBit logging is performed through a combined reaming or dummy Bottom Hole Assembly (BHA) and consist of special ThruBit tools such as a portal bit, an hang off sub, and a flapper float valve. The ThruBit logging tools are run on wireline, pumped outside the portal bit, and hanged on a hang-off sub; the cable is then unlatched and retrieved after powering up thus confirming that the ThruBit logging tools are functioning. The logging data is finally recorded in the ThruBit logging tools memory while pulling out of hole.
The ThruBit logging technique was performed successfully across interbedded formations: a detailed operating procedure was developed to minimize stationary time to account for the differential sticking risk. It allowed to save three days of rig time and it shorten the time between drilling the section and running the lower completion, thus reducing the risks related to open hole exposure time. ThruBit logging is a true game changer in acquiring the formation evaluation logs in challenging downhole conditions, reducing stuck pipe risks and saving time.
Continuous Flow Synthesis of Petroleum Sulfonates from Crude Oil and Formulation into Nano-Surfactants for Cost Efficient Oil Mobilization
Authors: Alzobaidi Shehab , Gizzatov Ayrat , Abdel-Fattah Amr I. , Mashat Afnan 
Published: October 2018

Abstract
The oil mobilization in tertiary mode using chemicals has been shown to be a promising approach. In such technique, surfactants with or without polymers, designed for specific reservoir conditions, are added into water during water flooding to further drive remaining oil out of the porous structure of the reservoir rock into production wells. The success of the method depends on the cost of the chemicals used and the amount of the additional incremental oil mobilization achieved beyond water flooding. Thus, utilizing reservoir-compatible and inexpensive surfactants is a key. Petroleum sulfonates are some of the most abundant and inexpensive surfactants that can be made available at the scale required for efficient oil mobilization operations. However, petroleum sulfonates lack solubility in harsh reservoir conditions which makes them rather inapplicable for reservoirs with high salt content (e.g. &gt; 50,000 ppm) and high temperature (e.g. 100 °C). We have successfully developed a simple, one-step nano-encapsulation technique to transform petroleum sulfonates into nano-sized multi-emulsion droplets in high salinity injection water featuring long-term stability at high temperatures. To further improve the economics and sustainability of such NanoSurfactants (NS), we developed a continuous and cost-effective synthesis process of petroleum sulfonates, directly from crude oil. The in-house-produced sulfonates were then formulated into a NS solution in high salinity injection water utilizing our encapsulation method. Results showed that petroleum sulfonates were successfully synthesized as seen from NMR analysis. The formulated NS was persistently stable at reservoir conditions, altered the wettability of the oil-wet rock as verified by contact angle measurements, and triggered crude oil release from the rock by spontaneous imbibition. This work provides a solution to produce petroleum sulfonates and formulate NS on-site for use in cost-efficient oil mobilization operations in high salinity and high temperature reservoirs.
Utilizing Artificial Intelligence Techniques for Predicting Rock Failure Parameters
Authors: Negara Ardiansyah , Ali Syed , AlDhamen Ali , Kesserwan Hasan , Nair Asok , Aleid Zahra 
Published: October 2018

Abstract
Maintaining a stable borehole is one of the major tasks during drilling operations. During the drilling, borehole breakout and drilling induced fractures are the two main instability problems which may lead to stuck pipe, sidetracking, and loss of circulation. To evaluate the stability of a wellbore, a constitutive model is required to estimate the stresses around the wellbore coupled with a failure criterion to predict the ultimate strength of reservoir rocks. The Mohr-Coulomb failure criterion is one of the commonly accepted criteria for rock strength estimation at a given state of stress. This failure criterion is mainly contributed from the cohesion and coefficient of internal friction parameters, which are determined by laboratory measurements. The laboratory measurements, although more reliable, are expensive and time-consuming. This paper discusses artificial intelligence models particularly multilayer perceptron (MLP) and support-vector regression (SVR) for predicting cohesion and coefficient of internal friction from elemental spectroscopy and petrophysical properties.
Elemental spectroscopy, density, porosity, cohesion, and coefficient of internal friction data presented in this paper are based on various geological formations. Cohesion and coefficient of internal friction are determined through a rock mechanical test in the laboratory, while elemental spectroscopy data were obtained from X-ray fluorescence (XRF) analysis. We divide the data set into training and testing data. Training data is used to train MLP and SVR then establishes the cohesion prediction models. Similarly, training data is used to train and construct the MLP and SVR-based coefficient of internal friction models. Both models are then examined using the testing data.
Cohesion and coefficient of internal friction predicted from MLP and SVR match well with the laboratory measurements. Two quantitative measures for estimation accuracy are used including coefficient of determination and mean absolute percentage error. Cross-correlation plots of predicted cohesion and coefficient of internal friction and the experimental results show very good coefficient of determination and relatively small error. The results demonstrate that amongst the MLP and SVR models, the models whose inputs are grain density, porosity, and elemental spectroscopy are the best models. From a practical point of view, the application of artificial intelligence techniques as a new method for indirect estimation of rock failure parameters are beneficial especially when the amount of core samples are relatively few.
Predicting Formation Tops while Drilling Using Artificial Intelligence
Authors: Al-AbdulJabbar Ahmad , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez 
Published: October 2018

Abstract
Formation tops is one of the important information that is gathered during the exploration and delineation phase. This valuable information aids in setting the casing properly during the development phase and ensure proper zonal isolation between different zones. Every time a new well is drilled, actual formation tops are picked using various methods such as rate of penetration (ROP) charts, gamma ray (GR), formation cuttings and mud logging. These data are used in updating the geological model and in ensuring a proper zonal isolation in critical sections. Each of these methods has its own advantages and limitations such as cost, accuracy, and man power. Most of these methods suffer from a lag in time or depth which prevents the formation tops from being picked instantaneously.
The goal of this paper is to introduce a better method for picking formation tops. It can be a potential alternative to replace other more expensive techniques. The new technique involves the use of drilling mechanical parameters along with the rate of penetration to increase the accuracy of prediction. This will help to detect a true increase or decrease in ROP even if the drilling parameters are fluctuating. Field data were gathered from two wells with the same bit size and the same formation type. The data were screened and cleaned from any outliers or noise using six different algorithms while retaining the data quality and representation. Using six inputs and four outputs, 30 different sensitivity analyses were conducted including using artificial neural network (ANN) to achieve the best results and prediction accuracy. Well-A was used to train and test the data with 70/30 ratio, while well-B was totally unseen data.
The results obtained showed that ANN can predict formation tops with great accuracy. The best result was found using ANN with 20 neurons and one layer in which correlation of coefficient (R) was 0.94 and 0.98 for both wells. With this new technique, detecting formation changes will be faster compared to other methods since no logs have to be processed and nor any wait is required for cuttings to reach the surface. The formations can therefore be picked in real-time with good accuracy at almost no extra costs because it uses the real-time data which is already available.
Achieving Higher Retardation of Emulsified Acid by Additive Optimization
Authors: Sidaoui Ziad , Aly Moustafa Taha , Al-Murisi Mohammed Abdullah , Qiu Xiangdong 
Published: October 2018

Abstract
Emulsified acid has proven to be very effective in both matrix acidizing and fracturing treatments. It has become the preferred stimulation acid system due to the significant reduction in tubing corrosion compared to straight acids and due to the reaction retardation, which allows it to penetrate deep into the formation before it breaks down and the reaction starts. The goal in the treatment is for the fluid to reach the formation while the acid phase is still encapsulated in the diesel one. Therefore, determining the optimal formulation of the emulsified acid system is essential for efficient well stimulation.
The objective of this work is to make the emulsified acid a fit-for-purpose system. This is achieved by investigating the effect of iron control and chelating agents on the stability and reaction with dolomite. Extensive testing is conducted to determine and select the effective concentration of the iron control and chelating agents to meet the needed stability to stimulate oil and gas wells.
This work includes the measurement of the stability of emulsified acid and the reaction weight loss as a function of the concentration of these agents at different periods of heating time. The tests are conducted at 135°C with a concentration of 28 wt% HCl and an acid-to-oil ratio of 70:30. For each agent, the concentration is reduced by one-third, starting from an initial concentration. The results show that the most-stable emulsified acid is achieved with no iron control agent and with an initial concentration of chelating agent. Furthermore, different concentrations of iron control agent result in a notable change, especially after 2 hours of heating. As for the chelating agent, its optimal amount is the original concentration; further increases in concentration do not show a specific trend. Moreover, increasing or decreasing the amount to four-thirds or two-thirds of the initial concentration has the same effect on the reaction weight loss.
The added value this work brings is the fit-for-purpose application of the emulsified acid system in which optimal concentrations of the ingredients result in an emulsified acid system that is better suited for a particular reservoir.