bluuebunny/crossref_metadata_2025 huggingface dataset:
Macroscopic Scale Interactions of Smartwater with Alkaline Chemicals for Enhanced Oil Recovery in Carbonates
Authors: Alabdullateef Muhannad , Ayirala Subhash , Al-Saleh Salah , Yousef Ali
Published: October 2019

SmartWater flooding through tuning of injection water salinity and ionic composition is recently gaining good attention for enhanced oil recovery (EOR) in carbonates. The development of new hybrid recovery methods by capitalizing on the synergy with SmartWater can provide one potential optimization route for achieving more economic and effective EOR applications in the field.

In this experimental investigation, we evaluated the synergy of alkali with SmartWater through interfacial tension and contact angle measurements. These measurements were performed at reservoir conditions (2,500 psi and 70°C) using the crude oil and rock substrates from a carbonate reservoir. The high pH common alkali (NaOH) was used at dilute concentrations of 0.1 wt% in two different SmartWater recipes at a fixed low salinity (5,760 ppm TDS). The SmartWater recipes chosen include; 10-times reduced salinity seawater and low salinity water enriched with sulfates and without the divalent cations together with the seawater as baseline.

The contact angle results with high salinity seawater showed the strongly oil-wet behavior (140°) for a carbonate surface, which was favorably altered toward an intermediate-wet state (90°) with SmartWater recipes. The addition of alkali to 10-times reduced salinity seawater increased the contact angle to 152° due to alkali precipitate (formed by the reaction with divalent cations) preventing the interaction of key ions in the SmartWater with carbonate rock surface. A significant shift in the wettability toward a water - wet state (70°) was obtained by the addition of alkali to the SmartWater-enriched with sulfates to confirm the major role of pH on wettability alteration. In addition a reduction in the interfacial tension from 16.6 mN/m to about 7.2 mN/m was achieved by the addition of alkali to the SmartWater-enriched with sulfates in comparison to seawater, as a result of favorable alkali interactions with carboxylic acid groups present in the crude oil. The compounding of these beneficial wettability alteration and interfacial tension reduction effects observed with alkaline chemicals would further reduce capillary forces to mobilize relatively higher amounts of waterflood residual oil in carbonates.

This study is of practical significance as it successfully demonstrates the positive impact of combining SmartWater with alkaline chemicals for both wettability alteration and IFT reduction in carbonates at reservoir conditions. It also opens up a new avenue to exploit the use of synergistic alkaline based hybrid recovery processes for efficient and economical EOR applications in carbonate reservoirs.
The Future of Nonmetallic Composite Materials in Upstream Applications
Authors: Badeghaish Wael , Noui-Mehidi Mohamed , Salazar Oscar
Published: October 2019

Corrosion in oil and gas operations is generally caused by water, carbon dioxide (CO2) and hydrogen sulfide (H2S), and can be aggravated in downhole applications where high temperatures combination with H2S introduce other challenges related to corrosion and iron sulfide (FeS) scale formation. The repair costs from corrosion attacks are very high and associated failures have effects on plant production rates and process integrity. To overcome this existing problem in upstream, nonmetallic composite materials were introduced for drilling, tubular and completions in high risk, corrosive environments. The goal being to increase the well life cycle and minimize the effect of corrosion, scale and friction in carbon steel tubulars. The new proposed materials have light weight, high strength, and superior fatigue resistance in addition to an outstanding corrosion resistance that is able to surpass many metallic materials.

The economic analysis shows that utilization of nonmetallic tubulars and internal linings will yield substantial life cycle cost saving per well mainly due to the elimination of workover operations. However, with these advantages, composite materials pose several challenges such as single source provision, high initial cost of raw materials, the manufacturing process and the limitation of standards. As results, the polymer and composite solutions for upstream oil and gas are still very limited even in targeting low risk applications such as low temperature and pressure scenarios. Therefore, research & development (R&D) efforts are ongoing to increase the operation envelope and introduce cost effective raw materials for high-pressure, high temperature (HPHT) subsurface applications.

The present paper highlights practical examples of nonmetallic materials selection and qualification for upstream water injection/producer and hydrocarbon wells. Several future NM applications in upstream will be summarized. Challenges and R&D forward strategies are presented in order to expand the operation envelope of current materials and increase NM deployment to more complex wells, i.e., extended reach drilling (ERD).
The Dynamics of Drilling with Oil-Based Mud, 60:40 Oil-Water Ratio – Case History in South East Kuwait Fields
Authors: Sheer Shahad , Alotaibi Ali , Gadhiya Ketan , Al-Khaldy Meshal , Abhijit Dutta , Al-Failkawi Khaled , Al-Saadi Dhari , Al-Saeedi Abdullah , Hamed Abdulrahman , Al-Azmi Faisal , Jayprakash Girish
Published: October 2019

Drilling to the targeted depth of a well can be a challenge, considering the problems that may arise in the form of wellbore instability, mud losses, and/or differential sticking. The objective was to successfully drill a first-time implementation of an Oil-Based Mud (OBM) system with 60:40 Oil-Water Ratio (OWR).

The OBM system was maintained within the specified parameters in terms of mud weight, viscosity, and fluid loss. The addition of primary and secondary emulsifiers in the system enhanced electric stability (ES). Moreover, solid control equipment will be monitored continuously for immediate action if necessary. Contingency plan and a surplus of chemicals will be provided to ensure a smooth drilling and a swift movement of operations.

A fluid system was designed after extensive laboratory tests to analyze the optimal approach to drill using the first-time application of 60:40 OWR mud. It reduces the use of Diesel consumption by 26% in total OBM formulation, lowers the percentage of Low Gravity Solids (LGS) compared to the 80:20 OWR mud, and decreases the impact on the environment. Furthermore, the OBM was then reused in consequent wells with the addition of emulsifiers to reduce the cost.

This paper presents successful first-time applications of the 60:40 OWR fluid till the targeted lower Burgan formation, interbedded sandstone and shale formation. A complete laboratory analysis comparison between previous wells drilled and the current application indicates no difficulties were faced.
Structure Property Relationship of Novel Nano-Hybrids for Hydraulic Fracturing Applications
Authors: Kalgaonkar Rajendra , Baqader Nour , Alnoaimi Khalid , Sahu Qasim
Published: October 2019

The unique properties of polymer nano-hybrids, which not only make them obvious technology materials, but also provide a convenient macroscopic system to study fundamental scientific issues concerning confined and tethered polymers, have sparked the attention of material developers. Studying the formation, structure and dynamics of polymer nano-hybrids can lead to a better understanding of organic-inorganic hybrids, polymers in confined environment or at a solid interface. Proppant are an integral part of hydraulic fracturing operations. Resin coated proppants are widely used in hydraulic fracturing applications to increase the strength of proppant material to withstand closure stresses and to mitigate any proppant flowback. In this paper we showcase the development of novel nano-hybrid materials that enhance the proppant physico-chemical properties.

We present an investigation of novel polymer nano-hybrids based on emulsified resin and nanofillers having one dimension in nanoscale. The resins used for proppant coating are introduced as a water external emulsion, thus making them compatible with the aqueous fracturing fluids. We show that by using a solid resin-based emulsion system as proppant coating material we could introduce this system on the fly, along with the fracturing fluid without facing any incompatibility issues between the hydrophobic resin and the aqueous fracturing fluid. We further show that by using tactoid-based filler materials dispersed within the emulsified resin we could tremendously enhance the overall physico-chemical properties of the proppants. It is also shown that this property enhancement is dependent on the structure of the nano-hybrid.

In polymer nano-hybrids using tactoid based nano-fillers, better dispersion of nano-fillers in the polymer matrix can be achieved by organic modification filler surface, rendering the filler surface hydrophobic, thereby facilitating the delamination of the tactoid individual layers into nanoscale platelets by the polymer chains. The dispersion of nano-size layers in the resin matrix, markedly improves physico-chemical properties as compared to pristine resin. We have shown that the delamination of the individual tactoid layers and their uniform dispersion in the resin matrix was the key aspect that governed the tremendous property increment in the nano-hybrid coated proppants. A microstructural evaluation of these nano-hybrid coated proppants is presented and correlated to the proppant property enhancement.

Novelty of this paper is the development of new nano-hybrid based proppant coating materials that lead to tremendous physico-chemical property enhancement as well as on-the-fly deployment of the proppant coating material along with fracturing fluid due to enhanced compatibility.
Wettability Measurements of Mixed Clay Minerals at Elevated Temperature and Pressure: Implications for CO2 Geo-Storage
Authors: Fauziah Cut Aja , Al-Khdheeawi Emad A. , Barifcani Ahmed , Iglauer Stefan
Published: October 2019

Wettability of CO2/brine/clay has an important role in CO2 geo-sequestration efficiency as it highly affects the fluid flow through a porous medium. In this context, it is vital to measure the wettability of the clays. In addition, many previous studies have been conducted to investigate the wettability of pure clay minerals. Thus, in this study, we systematically measured the wettability of a mixture of different clay minerals (i.e. 14 wt% kaolinite, 48 wt% illite and 38 wt% montmorillonite). Both advancing and receding contact angles were measured at four different pressures (ranging from 5 MPa to 20 MPa) and two different temperatures; 305 K and 333 K. Then, for each clay minerals suspension with the brine, the zeta potential analysis was conducted to examine the clay's correlation to macroscopic contact angle. The results illustrate that the advancing and receding contact angles increased with increasing pressure (i.e. the wettability of the mixed clay has been altered from weakly water-wet to intermediate-wet with the pressure increased from 5 to 20 MPa). However, the results show that mixed clay minerals contact angle was a slight decrease with increasing temperature from 305 K and 333 K. Therefore, we conclude that the mixed clay minerals contact angle is highly affected by reservoir pressure and that higher pressures lead to reduce the CO2 storage capacity and contaminate security of the mixed clay minerals. This study has various significant implications for CO2 flow in porous media, CO2 entrapment in the deep geological reservoirs for CO2 geo-sequestration, and CO2 dynamics and spreading in geological formations for CO2 injection of methane recovery.
Semi-Analytical Analysis of Peak Production Rates in Unconventional, Boundary-Dominated Gas Reservoirs with Adsorptive Storage
Authors: Alzaabi Abdulla , King Gregory
Published: October 2019

The objective of this study was to develop tools to analyze the production profile of unconventional gas reservoirs where adsorption is a dominant storage mechanism. Specifically, the research is focused on analyzing the conditions that affect the time needed to achieve peak gas production rate. To this end, we have successfully derived the analytical expressions for the reservoir pressures at which peak gas production occurs under various operating scenarios.

The methodology involves the development of a system of generalized two-phase material balance equations for boundary dominated flow in unconventional gas reservoirs where adsorption is a dominant storage mechanism. The resulting analytical ODEs are then solved numerically (Runge-Kutta) which yields a semi-analytical solution for pressure and saturation versus time. Once the pressure and saturations are determined numerically, gas and water production rates, along with their derivatives, are determined analytically and used to analyze the production profiles. Through the analytical derivatives, reservoir and fluid parameters can be modified to observe their effects on the time to peak gas rate.

In this study, three different well specifications were investigated (constant flowing well pressure, constant well drawdown, and constant water production rate) with only two of the three well specifications resulting in a peak gas production rate - no peak gas production rate was observed for the water rate specified wells. Furthermore, the developed semi-analytical model, under appropriate conditions, gives results comparable to numerical reservoir simulator. The paper will discuss conditions at which the material balance results are comparable to full reservoir simulation.

Through this research, a new material balance method has been developed that can be presented in different domains (pressure, time, and cumulative produced fluids domains). Also, the novel use of derivatives from the generalized material balance equations was applied in this research to analytically and graphically analyze the production profile. Furthermore, in addition to the peak gas production rate, additional inflection points were observed that have not been reported in the current literature.
Setting the Standard for Safety in the Offshore Access Industry
Authors: Nacheva Mina , Silianova Krissi , Mulders Tim
Published: October 2019

This paper is a combined review of the literature on the safety culture in the offshore industry as a whole and safety in the offshore access industry. As well as a review on best practices to incorporate new technologies and systems into an organisation. Safe offshore access is a challenge that all players in the offshore energy industry face, and setting the standards requires the continuous implementation of new technologies and higher managements' hands-on involvement in its implementation.

Finally, this paper looks at three key criteria that could bring the safety culture from being responsive to preventive and ultimately to proactive. It does so by evaluating the safety culture using the Hudson's safety culture ladder. In the end, it is always important to note that safety is the responsibility of everyone.
An Experimental Investigation of Polymer Performance in Harsh Carbonate Reservoir Conditions
Authors: Alfazazi Umar , Thomas Nithin Chacko , AlAmeri Waleed , Al-Shalabi Emad W. , Shaik Abdul Ravoof
Published: October 2019

Polymer flooding is a well-established enhanced oil recovery (EOR) technique for mobility control. However, several factors affect a successful application of polymer at field-scale including injectivity and retention. The latter two parameters can lead to poor polymer performance. This work investigates the flow behavior of an HPAM-based polymer (SAV10) in carbonate reservoirs under high-temperature and high-salinity (HTHS) conditions. Formation water sample as well as three-outcrop carbonate cores were utilize in this work. Rheological studies and injectivity tests were conducted on SAV10 at two different temperatures of 20 °C and 90 °C. Polymer dynamic retention tests were also conducted to assess polymer loss in porous media.

The results showed that the HPAM-based polymer has a good tolerance to salinity with a shear thinning behavior at reservoir flow rates and shear thickening behavior at well flow rates under temperature condition of 25 °C. The rheological studies also showed that this viscoelastic behavior disappears at higher temperatures of 90 °C. From injectivity tests, with increasing flow rate, resistance factor increases at 25 °C and decreases at 90 °C, which is related to polymer rheological behavior and in particular in-situ viscosity. In addition, resistance factor at 90 °C was lower than that of 25 °C due to the decrease in SAV10 retention as temperature increases. This paper recommends the use of polymer taper prior to brine postflush to better characterize resistance factor as well as the removal of backpressure to better describe polymer degradation. The paper provides more insight into the applicability of synthetic polymers (SAV10) in reservoirs with harsh conditions. The study also helps in better understanding of polymer flow behavior for designing successful field projects.
Building More Accurate Models for Different Reservoir Types and Oil Water Delineation
Authors: Zeybek Murat
Published: October 2019

Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir.

The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient non-linear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type.

It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner. In addition, field examples with classified reservoir types including flow tests supported the methodology.
Miscible Gas Injection as a Key Development Scenario for the Complex Reservoir with Low Permeability
Authors: Mukhametzyanov Iskander , Glavnov Nikolay
Published: October 2019

Currently, for the most oil companies it is possible to identify a general tendency that the reservoir permeability for the new prospects is decline. Reserves quality deterioration increases the risk of the future oil production failure. This paper describes the organization of an integrated approach to source data analysis, simulation model constructon and miscible displacement design in a low-permeable reservoir.

At the first stage, a reservoir fluid model is constructed. Based on the lack of a qualitative oil sample from the well (original sample was significantly depressurized during testing) and on the analysis of the fluid properties of the analog fields, the prediction of the main oil parameters was made. At the second stage, using static parameters of a low-permeable reservoir, probabilistic simulation models of the field was constructed, providing a coverage of the main spectrum of reservoir uncertainties. Further, import gas resources were estimated for the injection implementation.

The main result is an integrated assessment of the impact of uncertainties for oil properties and gas import resources on key economic indicators for a miscible displacement at the field with a low-permeable reservoir using the reservoir simulation model. The analysis verified the key parameters that have the greatest impact on the economy of the project, determined the threshold values for the volume of gas imports, and based on the feasibility study made recommendations on the choice of the pilot area for injection. A program for conducting additional laboratory experiments was also prepared, this study will allow the narrowing of the oil composition uncertainties and its interaction with injection gas. In addition, a program is developed to carry out special core experiments on gas injection, which will make it possible to correct the behavior of phase permeabilities for a miscible displacement.

This paper shows that on the basis of reservoir simulation an integrated approach organization for the verification, accounting and analysis of uncertainties on reservoir characteristics, fluid properties and volume of imported third-party gas allows to search for and select an economically viable and sustainable option to develop an oil field using miscible gas injection technology. An implementation of this approach provides a recovery factor increase from 7% to 25%.
Effect of Water/CO2 Ratio on Performance of CO2-Based EOR in a Sandstone Reservoir – Insights from Core Flood Tests and Simulations
Authors: Pourafshary Peyman , Al Khanbashi Iman , Mosavat Nader
Published: October 2019

Injection of water and gas are considered to be effective approaches in improving recovery from sandstone oil reservoirs. Different combinations of water and gas injection (such as continuous gas injection after water-flooding, simultaneous water and gas injection, and carbonated water injection) are used in oil fields to increase the recovery. The selection of the injection method and optimization of practical parameters, such as the water/gas ratio, improves the performance of this approach. Comprehensive experimental modeling techniques help specialists in the oil industry to design the most effective gas/water based enhanced oil recovery methods to produce more oil in a cheaper way.

In the first stage of this research, different experiments (such as core flooding) were carried out to study the performance of CO2-water EOR methods. Other parameters, such as gas solubility in oil and brine, oil swelling factor, oil viscosity reduction, gas diffusion coefficient, and gas utilization factor were measured and analyzed to investigate the mechanisms. At the next stage, gas/water injection in porous media was modeled. The model was in good agreement with experimental data. The confirmed model was used to analyze the main parameters of fluid flow in porous media, such as relative permeability. From the model, the optimized gas-based EOR method was selected to achieve the highest oil recovery.

In our study, oil recovery reached about 50% through water-flooding. Hence, a successful EOR approach is essential for a case with this amount of residual oil. Our experiments and models showed that simultaneous injection of water and gas with a water/gas ratio of 2.4:1 had the highest oil recovery factor (36%) in the studied sandstone formation, which makes the total recovery more than 85%. Compared to gas flooding, the gas/water injection schemes have a lower gas utilization factor, which reduces the operational cost in the fields.

Our comprehensive simulation studies, based on different experiments at core scale, provide an accurate and reliable approach to selecting the best gas injection scenario in the porous media. This methodology helps the industry to optimize the process from a technical and an economic point of view.
Characterization of Formation Damage and Fracture Choking in Hydraulically Induced Fractured Reservoirs Due to Asphaltene Deposition
Authors: Khurshid Ilyas , Al-Shalabi Emad W. , Al-Attar Hazim , Al-Neaimi Ahmed K.
Published: October 2019

Hydraulically induced fractures provide a significant fraction of oil supply to the world from unconventional reservoirs due to their high permeability. However, these fractures might choke because of the deposition of organic and in-organic particles. Among organic particles, asphaltene deposition severely reduces reservoir permeability causing an exponential drop in production. The objective of this study is to derive a model that characterizes formation damage and hydraulic fractures choking in unconventional reservoirs due to asphaltene deposition on fracture face and pore surface. This study also analyzes different factors affecting permeability alteration by asphaltene deposition in fractured reservoirs.

In this work, a 1D simulator is developed that predicts the performance of fractured reservoirs by solving the fluid flow governing equations for matrix and fractures. These flow equations were then incorporated with asphaltene deposition equations. The developed model considers constant temperature of the reservoir with negligible gravity and capillary forces. Sensitivity analysis was also performed to investigate the effect of three influential parameters on permeability alteration of fractured reservoirs by asphaltene deposition. These parameters include fracture-to-matrix permeability ratio, production time, and asphaltene concentration.

The study showed that asphaltene deposition could partially or completely choke fractures. This finding is in match with observations in the literature for asphaltene deposition and the consequent fracture choking. The sensitivity analysis showed that long production time and high asphaltene concentration have adverse effect on fracture permeability while matrix permeability was not much affected. On the other hand, low fracture-to-matrix ratio has a negligible effect on permeability of the simulated reservoir model. This work provides an insight into the detrimental effect of asphaltene deposition and estimates fracture choking in hydraulically fractured unconventional reservoirs with problematic oils.
Scale Prediction and Inhibition Design Using Machine Learning Techniques
Authors: Al-Hajri Nasser M. , AlGhamdi Abdullah
Published: October 2019

This paper will introduce a data driven methodology to predict scale formation and design its inhibition program in petroleum wells. The proposed methodology integrates and adds to the existing principles of production surveillance, chemistry, machine learning and probability theory in a comprehensive decision workflow to achieve its purpose. The proposed model was applied on a large and representative field sample to verify its results.

The method starts by collecting data such as ionic composition, pH, sample collection and inspection dates, and scale formation event. Then, collected data are classified or grouped based on production conditions. Calculation of chemical scale indexes is then made using techniques such as water saturation level, Langelier saturation index, Ryznar saturation index, and Puckorius scaling index. The machine learning part of the method starts by dividing the data into training and test sets (80% and 20%, respectively). Classification models such as support vector machine, K-nearest neighbors, gradient boosting, and decision tree classifier are all applied on collected data. Prediction results are then classified into a confusion matrix to be used as inputs for the probabilistic inhibition design model.

The scale inhibition program design is based on a probabilistic model that quantifies the uncertainty associated with each machine learning method. The scale prediction capability compared to actual inspection is presented into probability equations that are used in the cost model. The expected financial impact associated with applying any of the machine learning method is obtained from defining costs for scale removal and scale inhibition. These costs are factored into the probability equations in a manner that presents incurred costs and saved or avoided expenses expected from field application of any given machine learning model. The forecasted cost model is built on a base case method (i.e. current situation) to be used as a benchmark and foundation for the new scale inhibition program.

As will be presented in the paper, the results of applying the above techniques resulted in a scale prediction accuracy of 95% and realized three-folds of cost savings figures compared to existing programs.
Modeling of Smart Pigging for Pipeline Leak Detection: From Mathematical Formulation to Large-Scale Application
Authors: Thiberville Caitlyn , Wang Yanfang , Waltrich Paulo , Williams Wesley , Kam Seung Ihl
Published: October 2019

Although leak incidents continue, a pipeline remains the most reliable mode of transportation within the oil and gas industry. It becomes even more important today because the projection for new pipelines is expected to increase by 1 billion BOE through 2035. In addition, increasing number and length of subsea tiebacks face new challenges in term of data acquisition, monitoring, analysis, and remedial actions. Passive leak-detection methods commonly used in the industry have been successful with some limitations in that they often cannot detect small leaks and seeps. In addition to a thorough review of related topics, this study investigates how to create a framework for a smart pigging technique for pipeline leak detection, as an active leak detection method.

Numerical modeling of smart pigging for leak detection requires two crucial components: detailed mathematical descriptions for fluid-solid and solid-solid interactions around pig, and network modeling for the calculation of pressure and rate along the pipeline using iterative algorithms. The first step of this study is to build a numerical model that shows the motion of a pig along the pipeline with no leak, i.e., at a given injection rate, a pig first accelerates until it reaches its terminal velocity, beyond which the pig moves at a constant velocity. The second step is to construct a network model that consists of two pipeline segments (one upstream and the other downstream of leak location) through which the pig travels and at the junction of which fluid leak occurs. By putting these multiple mechanisms together and using resulting pressure signatures, this study presents a new method to predict the location and size of a leak present in pipeline.
Horizontal Well Casing Design Optimization & Implementation Case Study: Vibrations Management Through Enhanced Bottom Hole Assembly Design
Authors: Abaltusov Nikolay , Ryabov Anton , Dankov Aleksandr , Zaripov Elvir , Grishin Dmitriy , Teregulov Oleg
Published: October 2019

The objective of pilot testing was to optimize horizontal well construction cycle by decreasing the number of casing strings. The testing involved drilling of 13 wells, in which only production casing was run in hole instead of intermediate casing and a liner.

The key issue during drilling was failure of measurement tools due to high vibration. This paper covers decisions and actions being made to get a well with new casing design successfully drilled.

To mitigate the issues, the bottom hole assembly (BHA) behavior was modeled using a proprietary software for static and vibration analysis. Relevant diameters of stabilizers and drilling modes were selected. The interpreted computations were successfully used for drilling further wells.

For comprehensive approach, an optimal bit design was selected vibration mitigation wise.

Three-axis vibration sensors installed in the BHA enabled selecting of optimal drilling modes in real time.

Drilling of triple casing wells showed reduction in actual well construction time compared to quadruple casing by 20% on the average.

The record-setting well was drilled in 8.6 less days compared to a similar 4-string well. Furthermore, BHA with mud motor was used, which is less expensive compared to a BHA with Rotary Steerable System (RSS).

The three-string design was used at the fields in question for the first time.

The accumulated experience makes it possible to use this technology at other fields, where horizontal wells are drilled.
Well Placement Optimization with an Artificial Intelligence Method Applied to Brugge Field
Authors: Bruyelle Jérémie , Guérillot Dominique
Published: October 2019

Planning the position of a new well is an essential task to increase hydrocarbon production. However, trying to capture the uncertainty related to the geological properties, an ensemble of geological realizations of the models must be considered. The objective can be to identify the locations of the new wells that maximize the average oil recovery or Net Present Value (NPV), for an ensemble of geological models. Also, considering an ensemble of geological models, an objective can be to minimize the standard deviation of the NPV (or cumulative oil recovery). Reducing the uncertainty on the NPV leads to reduce the risk for the placement of the new wells. These two objectives can be defined with a "mean-standard deviation" formulation of the objective function. Following the weight given to each objective, the placement of the wells is not the same. To know all the well-placement possibilities and associated risk, many optimization problems must be done. Such as procedures, require the use of optimization method and reservoirs simulations on each reservoir model. This optimization problem leads to a high number of reservoir simulation to determine the appropriate location and can be expensive in computation time. To reduce the computation time, a method consists in to substitute the reservoir simulator by a meta-model. In this paper, the use of an artificial neural network as a proxy model is considered. The objective is to propose a method to speed up the well-placement optimization process using a proxy model based on an artificial intelligence technique to replace the reservoir simulator. The proposed methodology considers an ensemble of realization and aims to provide an overview of solutions in an economic point of view inspired by portfolio optimization problems. An application of the methodology is presented for the Brugge field.
Flow Characteristics Through Gas Alternating Gas Injection During Enhanced Gas Recovery
Authors: Mohammed Nuhu , Abubakar Abbas Jibrin , Enyi Godpower Chimagwu , Ghavami Ghasem Nasr
Published: October 2019

Gas and liquid flooding using carbon dioxide (CO2), nitrogen (N2), or brine solution have become one of the promising enhanced gas (EGR) and oil recovery (EOR) technologies for residual hydrocarbons (HCs) enhancement in conventional oil and gas reservoir respectively. However, the flow mechanism between the displacing and displaced fluids are not yet clear, especially for the novel gas alternating gas injection method adopted in this study. This experimental study investigates the flow mechanism of N2-CO2-CH4 through gas alternating gas injection techniques in consolidated rocks during EGR. The research presents a better flow behaviour characteristic using a novel N2 alternating CO2 during EGR. These values were used in determining the optimum injection rate with the minimum in situ mixing and high displacement front. An experimental laboratory core flooding, experiment was done to imitate a detailed process of an unsteady state N2-CO2-CH4 displacement in Bandera grey core sample at 35-40°C of temperature, 1500 psig of pressure, and at 0.2, 0.4, 0.6, 0.8 and 1.0 ml/min N2 alternating CO2 injection rates to evaluate the displacement flow characteristics, such as diffusion coefficient, dispersion coefficient, density and viscosity, mobility ratio, and dispersivity. The CO2 was injected after 4-5 cm3 of N2 injection throughout the runs at the experimental condition. The findings indicated that gas alternating gas injection technique presents a better flow behaviour characteristic compared to that of individual CO2 or N2 injection. Such prominent behaviour was observed at 0.4 ml/min injection, with higher displacement front and longer CO2 breakthrough time. The mobility ratio of N2-CO2-CH4 was lower compared to that of N2-CH4 and CO2-CH4. This was due to the inclusion of nitrogen which acts as a barrier between the CO2 and displaced CH4. The later contributed significantly for the delayed in CO2 breakthrough especially at lower injection rates (0.2-0.4 ml/min) during the gas alternating gas EGR process. The overall molecular diffusion coefficients were found to be 22.99, 18.48 and 17.33 ×10-8 m2/s for N2-CH4, CO2-CH4, and CO2-N2 binary interaction respectively at the test condition. The dispersion coefficient increases with an increase in the injection rate due to rise in the interstitial velocity as the CO2 plume traverses through the core sample during the EGR process.
Understanding O/G Shale Reservoir Tortuosity by Imaging Characterizations
Authors: Sewailan Mohammad , Al-Bazzaz Waleed
Published: October 2019

A shale reservoir rock sample has been imaged successfully at 40X (millimeter scale), 400X (micrometer scale), and 4000X (nanometer scale). All captured images have been processed with morphological approach utilizing big data for porosity with pore size distribution as well as tortuosity. 1D, 2D and 3D pre-logic models are developed. And heterogeneity post-logic models are also developed. Nano pores are dominated in shale rock; as a result, the tortuous paths recognized are very complex yet very hopeful for many production scenarios.

The prepared shale rock samples in the form of rock fragments will be imaged and characterized for porosity morphology, pore size distributions, and tortuosity in 2D format utilizing SEM-BSE imaging techniques. The generated images will be quantified using pre-defined logic (10-classes of pore ranges, pore counts, pore frequency percent, and pore area). The data generated will be used to estimate tortuosity. Tortuosity investigations are set for different magnifications X40-millimeter scale, X400-micrometer scale, and X4000-nanometer scale, yielding the total formation/ sample experiments to become 3 magnifications X 1 sample = 3 experiment suites to ensure tortuosity representations for all shale pore magnification.

The overall objective is to increase shale reservoir knowledge and awareness of imaging characterizations that inherits increasingly sophisticated and unconventional technologies, which make the production of unconventional resources faster, accurate, and economically efficient. Another objective is to justify the exploitation of organically rich unconventional Oil and Gas (O&G) shale reservoirs that were always ignored by operators seeking easier production and faster returns on investments, as potential sources of significant natural gas and liquid reserves. The final objective is to introduce a reliable method to quantify tortuosity for unconventional reservoirs that seeks new physics in order to advance stimulation, advance reservoir characterization, and advance recovery efficiencies and production improvement.
Self-Healing PAM Composite Hydrogel for Water Shutoff at High Temperatures: Thermal and Rheological Investigations
Authors: Almohsin Ayman , Michal Feven , Alsharaeh Edreese , Bataweel Mohammed , Krishnan Mohan
Published: October 2019

Self-healing hydrogels have attracted much attention as they possess the ability to increase the lifetime of the materials and reduce the total cost during the process of long-term use. In this study, self-healing PAM-Zr(OH)4 hydrogel was prepared from acrylamide (AM) and Zr(OH)4 nanosheet filler using a free radical polymerization method. In addition, the polymerization of AM monomers was initiated by ammonium persulfate (APS) while tetramethylethylenediamine (TEMED) was used as a catalyst. The prepared composite hydrogel was cured at high temperature (i.e. 150°C) in order to simulate the conditions of the oil reservoirs. The thermal and rheological properties of the composite hydrogel were studied using thermogravimetric analyzer (TGA), differential scanning calorimetry (DSC) and dynamic mechanical analyzer (DMA). As observed from DSC, the free water (Wf) for PAM-Zr(OH)4 hydrogel was 0.39 and that of for neat-PAM was 0.34. The storage modulus (G′) and loss modulus (G″) for the PAM-Zr(OH)4 hydrogel were 2060 Pa and 644 Pa, whereas that of for neat PAM was 2000 Pa, 627 Pa respectively. From the results, incorporating fillers into the PAM matrix had significant improvements on the thermal and mechanical properties for PAM-Zr(OH)4 hydrogel in comparison to that of neat-PAM hydrogel. In addition, the composite hydrogel has demonstrated an excellent swelling behavior (i.e. swelling capacity up to 14,000%) while sustaining its gel strength (G′/G″). The kinetics of water absorption by the PAM-Zr(OH)4 hydrogel was pseudo-second-order with a second-order rate constant (k2) of 9.3×10−8 min g/g.
Enhanced Oil Recovery for Carbonate Oil Reservoir by Using Nano-Surfactant:Part II
Authors: Alhuraishawy Ali K. , Hamied Ramzy S. , Hammood Hajir A. , AL-Bazzaz Waleed Hussien
Published: October 2019

Excellent attempts have been made worldwide to improve oil recovery. Nano technology features in EOR have been the focus of attention over the past century. The introduction of nanotechnology began in the late 1980s and was created to synthesize fresh nano-materials by rearranging atoms and molecules. Based on the small partition size of NPs (1-100) nm, the optical, thermal, chemical and structural properties of the nanomaterial differ completely from those shown by either its atoms or bulk materials. It is also clear that surfactants contribute to the stability of nanoparticles and emulsions with the aim of reducing IFT and changing rock wettability to water-wet.

The main objective of this study is to investigate the effects of nano particles and surfactant on improving oil recovery in carbonate reservoirs. Two key parameters were examined: silica nano particles and silica nano particles with Sodium Dodecyl sulfate (SDS) as an anionic surfactant. Finally, flooding test showed that using 0.03wt% SiO2 with 0.158 wt% SDS can improve oil recovery by 15.1% and minimize residual oil saturation to 25.6%. X-ray powder diffraction (XRD) and field emission scanning electron microscope (FESEM) were also done for thin core samples and the results have been discussed.
The Interrelationship of Carbonate Reservoir Quality and Dynamic Characterization of Chemical Solutions for Potential of Enhanced Oil Recovery
Authors: Zhou Xianmin , Kamal Muhammad Shahzad
Published: October 2019

Understanding complex variation in dynamic characterizations of chemical solutions on the surface of rock related to different carbonate reservoir quality is one of the most challenging subjects in the enhanced oil recovery process because pore distribution, pore structure and petrophysical properties of carbonate reservoir have many differences. Carbonate reservoirs usually have heterogeneity, a wide range of pore levels and petrophysical parameters. This research aims to investigate systematically and explain the interrelationship between reservoir quality indexes (RQI) or flow zone indicator (FZI) and dynamic characterization of chemical solutions. The interrelationship derived can be applied to enhanced oil recovery in carbonate reservoirs.

Several laboratory studies were completed using carbonate core plugs and reservoir brine at reservoir conditions for dynamic characterization of chemical solutions for the potential application of enhanced oil recovery: 1). the evaluation of resistance factor (RF), residual resistance factor (RRF) and injectivity (I) of a sulfonated polymer; 2). dynamic adsorption and desorption of an amphoteric surfactant. The RQIs of carbonate core plugs are in the range of 0.74 to 1.91 µm.

Based on the results of this study, we found that the dynamic characterizations of chemical solutions depend on the RQI. The results from a sulfonated polymer solution injection tests show that RF and RRF increase with a decrease in RQI for both solutions of 0.1 wt% and 0.2 wt% polymer. However, there is a critical frontal velocity for such a polymer solution of 0.2 wt%. When the frontal velocity is more than critical frontal velocity, RRF has similar values with increase in front velocity. Liquid permeability loss at a concentration of 0.2 wt% is higher than that in the case of 0.1 wt%.

This paper provides a comprehensive overview of dynamic characterization of an amphoteric surfactant and sulfonated polymer for carbonate reservoir rocks with RQI and presents insights and large potential for application of chemically enhanced oil recovery in carbonate reservoirs.
Stuck Pipe Incidents Prediction Based On Data Analysis
Authors: Zhu Qi , Wang Zhaohui , Huang Jian
Published: October 2019

The process of oil and gas drilling is a complicated and uncertain field practice. Moreover, uncertainty and fuzziness of formation is also a threat to drilling safety. Due to inaccurate cognition of objective environment and decision-making errors of subjective consciousness, underground complex conditions and serious accidents are caused.

Stuck pipe is one kind of downhole accident with high probability, complex handling difficulty and cost of manpower and material resources in drilling engineering. To deal with the stuck pipe accident, workers on the well-site are often required to judge the geological conditions of formation drilled, to adjust drilling parameters, drilling fluid performance and other methods to avoid and remove. Without fixed reference basis and determination methods, it is difficult to provide early warnings.

Through the collection, while drilling in formation, such as geological lithology, designed well structure, real-time drilling fluid performance, rock physical properties of backflow cuttings, and drilling engineering parameter et,al. Artificial neural network learning model is used to predict the risk probability of stuck pipe.

In this paper, face to formation collapse stuck pipe, after collected and analyzed the physical and chemical properties of backflow cuttings, drilling fluid system performance, well-site drilling data and other well-site drilling parameters according to the influencing factors of collapse and stuck pipe, combined with computer intelligent technology, and predicted collapse stuck pipe risk probability in advance.

Through well-field data collected, the occurrence of stuck pipe is predicted successfully. Through accumulated database, the accuracy of prediction model is constantly improved and modified. Early warning mechanism, timely adjustment of drilling fluid additives, maintenance of drilling fluid system performance and improvement of drilling parameters for different formations, increase drilling speed and avoid unnecessary waiting time
Impact of AKAP6 Polymorphisms on Glioma Susceptibility and Prognosis
Authors: Zhang Ming , Zhao Yonglin , Zhao Junjie , Huang Tingqin , Wu Yuan
Published: October 2019

Purpose Glioma is the most common primary malignant brain tumor with high mortality and poor prognosis. Our aim was to clarify the correlation between AKAP6 gene polymorphisms and glioma susceptibility and prognosis in Chinese Han population. Methods Five single-nucleotide polymorphisms (SNPs) of AKAP6 were genotyped by Agena MassARRAY in 575 glioma patients and 500 healthy controls. Logistic regression model was utilized to calculate odds ratios (OR) and 95% confidence intervals (CI). The associations between polymorphisms and survival were assessed using the log-rank test, Kaplan-Meier analysis and Cox regression model. Results We found that rs2239647 polymorphism was strongly associated with an increased risk of glioma (OR = 1.90, p = 0.007) and a worse prognosis for glioma, especially in high-grade glioma (HR = 1.67, p = 0.034). Stratified analysis showed that rs2239647 increased the risk of glioma in female (OR = 1.62, p = 0.016). Whereas, rs4261436 (HR = 0.70, p = 0.045) and rs17522122 (HR = 0.75, p = 0.016) were associated with better prognosis of astrocytoma. In addition, we also found that surgical methods and chemotherapy are critical factors for the prognosis of glioma patients. Conclusions This study firstly provided evidence for the impact of AKAP6 polymorphisms on susceptibility and prognosis of glioma, suggesting AKAP6 variants might have potential roles in the etiology of glioma.