bluuebunny/crossref_metadata_2025 huggingface dataset:
Surface and Interfacial Tension Behavior in the Use of Ionic Liquids as Additives for Surfactant-based Enhanced Oil Recovery
Authors: Hanamertani Alvinda Sri , Pilus Rashidah M. , Manan Ninie A. , Ahmed Shehzad
Published: October 2018

Due to the favorable properties and versatility, the applications of ionic liquids (ILs) have been introduced in petroleum industry for different purposes including Enhanced Oil Recovery (EOR) processes. The ability of ILs to alter surface behavior of surfactant molecules by producing specific interactions with surfactant has motivated further investigation on its application to the important chemical EOR mechanisms, such as surface and interfacial tension lowering under reservoir conditions. The mixtures of in-house surfactant and different types of ILs (imidazolium- and eutectic-based ILs) as additives were formulated using different concentration ratio and prepared in fixed brine salinity. The surface tension (ST) and interfacial tension (IFT) behavior of the formulated mixtures were investigated by performing pendant and spinning drop tests at ambient and high temperature. In general, the extent of ST and IFT reduction was dependent on the type and concentration of ILs. The presence of ILs was able to lower both ST and IFT of surfactant solution and its effect as a function of ILs concentration was found to be more pronounced at high temperature. Of all ILs, eutectic-based IL showed the highest ability to decrease ST at any concentration used. Similarly, the eutectic-based IL was also regarded as the best ILs in lowering the surfactant solution/oil IFT even in the use of low concentration. From this study, it can be concluded that ILs can be proposed as new additives to alter the surface and interfacial behavior which are taking place through some surfactant-IL interactions and eventually improve surfactant performance in reducing ST and IFT. Surfactant solution with a lower ST due to the addition of ILs is expected to provide promising performance for surfactant-based EOR process involving gas mobility control application leading to enhancement of sweep efficiency, while a lower IFT value can provide favorable conditions for better oil displacement efficiency.
Machine Learning and Natural Language Processing for Automated Analysis of Drilling and Completion Data
Authors: Castiñeira David , Toronyi Robert , Saleri Nansen
Published: October 2018

During Drilling and Completion (D&C) operations large volumes of data are typically collected in oil and gas fields. These datasets typically contain hidden (valuable) information that could be used to improve D&C performance (e.g., by identifying bottlenecks in drilling operations, analyzing non-productive time, optimizing rig schedule based on key indicators, etc.). Unfortunately, D&C datasets are typically not well suited for data mining: they are not structured, they are text heavy and they often contain numerous gaps and errors that hinder automated pre-processing techniques. In this paper, an innovative method to automatically extract smart analytics and opportunities from D&C reports is presented.

Initially, a combination of Natural Language Processing, Data Mining, and Machine Learning algorithms are used to quality check a large volume of drilling data (including the text in the daily drilling reports), extract crucial information, and predict the non-productive time and its type. This results in a significant reduction of the labor-intensive quality check task for thousands of datasets and also the unbiased classification of the events. Then, the D&C datasets are integrated with other data sources such as production, geology, reservoir, etc. to generate a set of crucial drilling and reservoir management metrics.

The proposed method, which was successfully applied to fields in North and South America, is applied here to two onshore fields located in the Middle East. By applying the developed tool, the data processing and integration time that used to take months to accomplish could be reduced to only a few days. In addition, analyzing metrics such as the Drilling Efficiency Index, normalized drilling days for each field and well type, cost analysis, detailed analysis of non-productive time, effect of completion parameters on production, design efficiency, etc. enabled us to quickly identify the D&C bottlenecks in each field and provide customized solutions to diagnose each problem. In addition, the historical data was used to improve future rig scheduling and resource allocation by applying advanced optimization algorithms with cumulative oil production, net present value, and operation time as the objective functions. In the final stage, the results were vetted by the experts to assure it meet the best D&C practices. The novelty of the presented method lies in using advanced technologies such as Natural Language Processing, Data Mining and Machine learning to QC, mine, integrate and analyze large volumes of D&C data in a very short time, find the bottlenecks and optimize the future plan with evident benefits of improving D&C performance and capital efficiency from a global reservoir management perspective.
Predicting the Optimum Concentration of Partially Hydrolyzed Polyacrylamide Polymer in Brine Solutions for Better Oil Recovery, Experimental Study
Authors: Khamis Mohammed A. , Omer Omer A. , Kinawy Mostafa M.
Published: October 2018

Polymer injection is one of the most applications used in enhanced oil recovery. In order to achieve better sweeping efficiency, polymer is added to the injected water to increase its viscosity and ultimately minimize the viscous fingering. Partially hydrolyzed polyacrylamide (HPAM) is one of the polyacrylamide groups. It is characterized by the shape of straight chain polymer of acrylamide monomers in which some of it has been hydrolyzed. The viscosity of the polymer solution should be maintained in order to keep better sweep efficiency. Salinity, polymer concentration and temperature are the most important factors that strongly affect the polymer viscosity and behavior. The aim objective of this study is to estimate the optimum polymer concentration based on the suitable polymer solution viscosity. This viscosity will be suitable for preferable mobility ratio. In this work, five groups of polymer solutions were prepared with different salinities. In each group, several polymer solutions were prepared at different polymer concentration. The viscosity of prepared solutions was measured at different temperatures. New models correlate the flow behavior index (n) and flow consistency index (k) with polymer salinity, polymer concentration and temperature were developed and validated using the experimental data. In order to estimate the required optimum polymer concentration, the developed models were combined with other developed models that describe the polymer shear rate in porous media. Results show that, the cross plots of the measured and corresponded calculated (n) and (k) values indicated better prediction compared with the latest published correlations with a squared correlation coefficient of 0.9912 and 0.9962 respectively.

In addition, the calculated average relative error of the predicted (n) and (k) were 0.97 % and 6.07% correspondingly. Using these models, the power law viscosity equation and shear rate in porous media equation, the required polymer concentration can be estimated with high accuracy. Consequently the required optimum polymer concentration needed to achieve better sweeping efficiency can be determined and therefore enhance the oil recovery. This technique will save time and effort spent to find the optimum polymer concentration using the traditional methods.
Conformance Improvement in Oil Reservoirs by Use of Microemulsions
Authors: Torrealba V. A. , Hoteit H. King
Published: October 2018

The performance of many improved and enhanced oil recovery techniques in conventional reservoirs is frequently degraded by conformance problems. The presence of high permeability streaks or thief layers between injection and production wells typically results in pre-mature water breakthrough, high water cut and deficient volumetric sweep. As a result, significant oil volumes in the reservoir may not be contacted by the injection fluid.

Several conformance improvement techniques (e.g. foams, gels, resins) have been developed and practiced in improved oil recovery operations. Each technique has its own advantages and limitations related to deployment practicality, effectiveness, and durability. In this paper, we introduce a novel conformance improvement method (CIM) that we consider to be practical, effective and durable. The CIM process consists of cyclical injections of pulse slugs of surfactant alternating with brine. The surfactant slug compositions are selected based on the rheological behavior of the microemulsion phase. The chemical slugs are configured such that the viscosity of the injected fluids is kept low to preserve injectivity and to ensure invasion of the conformance agent towards the thief zones. The trailing brine slugs are designed to produce a high-viscosity microemulsion as they mix with the leading surfactant slugs in the reservoir. The proposed process leads to a reduction in the effective mobility of the fluids in the thief layers. As a result, the chase waterflood would divert into previously uncontacted layers to improve sweep efficiency.

The potential of the proposed CIM in improving oil recovery is demonstrated by various simulations of reservoir cases under waterflooding. We performed various sensitivities to investigate the effectiveness of the proposed process that include well-spacing, permeability contrast, size of the thief layers, heterogeneity, and size of the chemical pulse slugs. Simulations showed that this process is effective in addressing reservoir conformance issues, and therefore it has the potential to improve sweep efficiency and recovery factor in reservoir with distinct thief layers. The treatment surfactant volumes are relatively small, which enables this process to be cost-effective.
4D Seismic Monitoring of a CO2-EOR Demonstration Project in a Desert Environment: Acquisition, Processing and Initial Results
Authors: Smith Robert , Bakulin Andrey , Jervis Mike , Hemyari Emad , Alramadhan Abdullah , Erickson Kevin
Published: October 2018

Saudi Aramco recently started the company's first CO2-EOR demonstration project in an onshore carbonate reservoir. Time-lapse (4D) seismic has proven to be a valuable reservoir management tool for monitoring the areal expansion of CO2 plumes in many similar projects around the world. However, the complex and dynamic nature of the near surface encountered in the desert environments of the Middle East results in high levels of 4D noise. This noise, coupled with the weak 4D signal expected from injection into a stiff carbonate reservoir, makes mapping the time lapse signal very challenging. The objective of this project was to develop a highly repeatable system capable of detecting small reservoir changes related to CO2 injection to enable the plume expansion to be tracked over time.

Achieving highly repeatable seismic data requires specialized seismic acquisition and dedicated processing. A novel acquisition system using buried receivers was adopted to reduce 4D noise resulting from near-surface variations. To minimize the non-repeatability inherent in using surface sources, a differential GPS guidance system was implemented to ensure high positioning accuracy. Even with these acquisition efforts, a fit-for-purpose 4D processing workflow was necessary to further reduce differences between surveys.

Despite the challenges faced, outstanding data repeatability has been achieved, with mean NRMS values of less than 5% for data acquired during the same season. This level of repeatability is comparable to data acquired in marine 4D surveys and has resulted in the detection of the small 4D signal caused by CO2 injection. Frequent monitor surveys, with one full survey acquired every four weeks, shows the CO2 plume growing over time with increasing injection volume. While the observed CO2 plume largely correlates to available engineering data, discrepancies have been identified when compared with the predicted seismic response based on the reservoir simulation model. This indicates that 4D seismic can be used to constrain the reservoir model, yielding a better history match and improved predictions to enable more informed engineering decisions to be made.

This is the first successful application of seismic monitoring of a carbonate reservoir in an area renowned for poor seismic data quality. To overcome the challenges, a novel hybrid acquisition system using buried sensors and surface sources was developed. Advances in the seismic processing workflow were also required to bring the 4D noise down to a level that enabled detection of the CO2 injection.
Ultra-low Interfacial Tension, Thermal Stability and Static Adsorption of Novel Viscoelastic Surfactant with Heavy Reservoir Oil
Authors: Janjua Aneeq Nasir , Sultan Abdullah S. , Kamal Muhammad Shahzad
Published: October 2018

Middle East reservoirs are usually characterized as high temperature and high salinity (HTHS). In chemical EOR, interfacial tension (IFT) is a key parameter that alters the reservoir environment. IFT measurements are challenging specially at high temperatures due to its dynamic nature. Viscoelastic surfactants are introduced because of their dual capability of lowering the IFT and improving the sweep efficiency of the reservoir. In this paper, the main objective is to determine ultralow IFT's and thermal stability that can be obtained from viscoelastic surfactants in the presence of heavy crude oil using spinning drop tensiometer (Kruss), thermogravimetric analyzer (TGA), nuclear magnetic resonance (NMR) and fourier transform infrared (FTIR) spectroscopy. Investigation of VES is performed with heavy reservoir oil (12cp at 90°C) and using high salinity formation brine (234,189 ppm). The solutions were prepared by the combination of viscoelastic surfactant and undiluted sea water and stirred until they attain equilibrium. Density and IFT at high temperatures are determined. Equilibrated solutions are used with heavy reservoir oil to determine the IFT reduction capability of viscoelastic surfactant at various concentrations from 0.1 to 1%. Results show a considerable reduction in IFT with viscoelastic surfactant up to 10−1 mNm−1 range. IFT reduction usually depends on the concentration of solutions used. Results also show that ultralow IFT was obtained at 50°C and 80°C. Encouraging results with TGA demonstrated that VES is thermally stable and show high resistance to temperatures up to 250°C. Long-term thermal stability up to 30 days at 90°C and 120°C temperatures was evaluated. 1H NMR show stability in structure while 13C NMR results show minor structural changes in the aliphatic region. FTIR results indicated good thermal stability with strong bonding between C-H and C=O. Static adsorption is evaluated by shaking the powdered core samples with VES at two different high 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. Experimental results indicate two major effects. Firstly, ultralow IFT obtained with the novel viscoelastic surfactant and it is thermal stable at high temperatures. Secondly, viscoelastic surfactant significantly reduces retention at high temperatures when compared with low temperatures. They are excellent additives in chemical EOR for HTHS conditions. They are also very useful when we have heavy reservoir oil and where IFT reduction is required to mobilize the oil and improve the sweep efficiency of the reservoir.
Customized Drilling Fluids Design to Drill Challenging Sections Using High-Performance Water-Based Mud
Authors: Pino Rafael M. , Elhabrouk Ihab , Addagalla Ajay , Jadhav Prakash B.
Published: October 2018

This paper presents a customized water-based drilling fluids design for drilling challengig sections through varying formations. The offset wells were reviewed to identify the issues while drilling the trajectory through troublesome reactive and depleted formations that showed wellbore stability issues, stuck pipe incidents, and induced severe losses.

Additional problems experienced while drilling include shale dispersion, resulting in fine solids buildup in the drilling fluid, and the adherence of shale to the drill pipe and bit, reducing penetration rates. The customized drilling and completions fluids system was designed for different intervals. The system was developed with the following objectives in mind: improved hole stability through reactive formations; enhanced hole-cleaning efficiency at critical angles; minimized risk of stuck pipe across depleted formations with high porosity and permeability; minimized or non-induced losses to formation utilizing a unique wellbore strengthening technique; and improved rate of penetration to optimize drilling efficiency.

This paper describes the customized high-performance water-based mud (HPWBM) design and performance. A comprehensive engineered approach addressed the challenges of drilling horizontal wells by using a high-performance aluminum complex and polyamine chemistry to improve wellbore stability.

This approach for drilling fluid chemistry provides an alternative replacement for previously used nonaqueous drilling fluids. Three wells were drilled successfully, and the lessons learned on these wells were incorporated in drilling subsequent wells to continue improving drilling performance.
Collaborative Design of a Bottomhole Assembly Improves Performance and Provides a Cost-Effective Solution in a Massive Extended-Reach Drill Project
Authors: Bin-Madhi Adel , Azher Mohammed Mushtaq , Ghazzawi Ayman , Al-Mutairi Yousef , Balka Muhammad Sarfraz , Al Hajri Huzam , Harbi Magbel
Published: October 2018

During the field-development life of a mature extended-reach drill (ERD) project, a wide range of drilling tools and practices were introduced to continuously improve drilling performance and well delivery times.

One of the main challenges encountered in the ERD wells was in the 12¼-in. curve section, and drilling through interbedded hard layers with severe downhole stick/slip and downhole vibrations. Historically, both motor and motorized rotary steerable system (MRSS) bottomhole assemblies (BHAs) were used to drill this section. However, the motor BHA's lower rate of penetration (ROP) and weight transfer problem cause it to be an economically inefficient strategy in contrast with the MRSS BHA, successfully drilled through all of the challenges with higher ROP and a relatively lower overall cost.

Driven by cost reduction necessity, an intensive engineering effort was implemented by the operator and service provider drilling engineering teams to change the motor BHA into a cost-effective drilling strategy for the challenging 12¼-in section.

Analyzing the design and performance of all previous motor BHAs led to identifying the main challenges. Detailed modeling was then performed, involving well trajectory design, BHA design optimization, hydraulics modeling, and torque and drag modeling. The modeling included static simulation as well as drillstring vibrations using finite element analysis (FEA) dynamic simulation. This extended engineering analysis improved the bit and BHA selection capability. Several drill bits and BHA options were modeled and simulated under different drilling conditions to determine the most stable configuration. Simultaneously through the dynamics simulation, a stable drilling parameters plan was generated to improve the drilling performance.

The modeling results indicated that the lighter BHA configuration minimized BHA - formation contact area, allowing for smoother and efficient weight transfer downhole. A reduction in BHA vibration produced a step improvement in ROP and drilling performance.

The engineering modeling results were implemented by replacing the previously used motor BHA drill collars with heavy-weight drillpipe and smaller size jars. This hardware change resulted in an unprecedented cost reduction, a 52% improvement over the previous motor BHA in delivering the challenging section, achieving multiple additional records, and 56% ROP improvement over the field. This paper will present the design process and the detailed results for each run. Recommendations will be provided on how this process can be applied to increase ROP performance and reduce the cost per foot for such drilling applications.
Effect of In-Situ Generation of Heat and Pressure on Phase Behavior of Gas Condensate
Authors: Hassan Amjed M. , Mahmoud Mohamed A. , Al-Majed Abdulaziz E. , Elkatatny Salaheldin M. , Al-Nakhli Ayman R. , Bataweel Mohammed A.
Published: October 2018

Condensate blockage reduces the gas deliverability from gas condensate reservoirs, when the reservoir pressure drops below the dew point pressure. Several techniques are commonly used to avoid condensate banking, by maintaining higher reservoir pressure. However, these methods required large investment and resulted in temporary improvement in the gas production. In this paper, the effect of heat and pressure generated by using a novel technique (thermochemical reaction) will be investigated on the phase behavior of an actual gas condensate reservoir.

Several treatments were discussed in this paper to evaluate their effectiveness in removing the liquid banking and improving the gas production. Then, the effect of chemical treatment on altering the phase behavior for condensate reservoir was studied. To simulate the actual operations of condensate treatment; actual reservoir fluids were used. Peng-Robinson equation of state (EOS) was used to develop the EOS-model, employing WinProp from CMG suite, based on available data from the studied reservoir. Flash calculations were conducted at surface conditions, and the phase properties were studied as a function of pressure and temperature.

Moreover, managing hydrocarbon dew point can reduce the condensate process, i.e. the dew point can be adjusted in such a way that prevents the hydrocarbon condensation. Chemical treatments might be used to reduce the dew point and improve the condensate removal process. In addition to that, hydrocarbon condensation might form if the formation temperature become less than the dew point temperature. Therefore, condensation can be prevented by increasing the temperature to keep it above the dew point temperature. In situ heat generation technology is used as a new technique of maximizing the heat penetration and improve recovery efficiency of gas condensate at lower cost compared to the current practices.
Synthesis and Experimental Investigation of Novel CNT-Polymer Nanocomposite to Enhance Borehole Stability at High Temperature Drilling Applications
Authors: Ahmad Hafiz Mudaser , Kamal Muhammad Shahzad , Al-Harthi Mamdouh A. , Elkatatny Salaheldin Mahmoud , Murtaza Muhammad Mobeen
Published: October 2018

The successful drilling operation of oil and gas wells required high quality of drilling fluids which can stabilize well formations and able to withstand deep wellbore conditions of elevated temperature. Wellbore formations are mainly composed of shale (soft clay) and are likely to destabilize upon interacting with water. The instability of wellbore is caused by the interactions of water with the formation that results in the swelling of shale. Specialized drilling fluids can overcome this issue by stabilizing wellbore formations.

The purpose of this study is to develop a novel CNT-polymer nanocomposite through in situ polymerization process and to enhance rheological properties, borehole stability and filtration characteristics for high-temperature and high-pressure drilling applications. The thermal stability of nanocomposite was assessed using TGA analysis. The nanocomposite concentration (2 w/v.%) was employed with the base drilling fluid to study the impact on rheological properties at elevated temperature from 100°F to 300°F and 300 psi pressure. The results showed that rheological properties (viscosity, yield point, gel strength) were stable up to 300°F with (2 w/v.%) concentration of nanocomposite. The HTHP filtration experiment showed that fluid loss of modified drilling fluid significantly reduced compared to the base drilling fluid. Shale dispersion experiments were carried out at (100°F, 200°F, 300°F) for a shale sample obtained from the actual drilling field of Saudi Arabia. The XRD analysis of shale sample showed 19% clay contents in the shale sample. The shale recovery performance indicated that using 2 w/v.% concentration of nanocomposite in the base drilling (modified drilling fluid) has significantly reduced the dispersion of shale (up to 90%) compared to the base drilling fluid. The linear shale swelling experiments were carried out using nanocomposite modified drilling fluid and it was observed that use of nanocomposite appreciably reduced the swelling of shale compared to the base drilling fluid.

The use of polymer nanocomposite as water-based drilling fluid additive enhances the rheological properties, filtration characteristics and borehole stability at high-temperature drilling applications.
Temperature Impact on Adsorption Contribution to Sequestration of CO2 in Immature Shale Formations in Saudi Arabia
Authors: Eliebid Mohammed , Mahmoud Mohamed , Al-Shehri Dhafer , Elkatatny Salaheldin , Abouelresh Mohamed , Shawabkeh Reyad
Published: October 2018

The environmental concerns to reduce carbon dioxide emissions have led to huge advancements in carbon capture and sequestration in different geological formations in the past two decades. Due to the high abundance of shale basins around the world, in recent years, CO2 sequestration potential in these formations has become an attractive option. However, most of the shale formations are considered immature to become shale oil or shale gas. These types of shale usually contain high organic matter (kerogen) generally expressed as total organic carbon (TOC) compared to mature shale reservoirs. The poor petrophysical properties of shale rocks in terms of porosity and permeability the adsorption capacity became a very significant factor that controls the amount of CO2 these formations can store. Previous experimental studies showed that high TOC indicates high adsorption capacity. Here adsorption of CO2, CH4 and 10%CO2/90%CH4, adsorption isotherms and adsorption thermodynamics were studied on intact three shales SH1, SH2 (immature) and SH3 (mature) from Qusaiba field in Southern Saudi Arabia at 50, 100 and 150°C. We attested that as CO2 amount increased, the adsorption capacity of the three shales increased accordingly justifying the good potential for using CO2 for enhanced improved methane recovery. Furthermore, the three shales exhibited diverse responses to the studied temperatures. SH1 and SH3 showed an endothermic trend from 50 to 100°C with a huge increase in the adsorption followed by an exothermic significant decline at 150°C. SH2 had no CH4 adsorption at 50°C and exhibited endothermic adsorption behavior; increasing the adsorption at elevated temperatures. These variations in adsorption comportment resulted from thermally induced alterations in the clay minerals crystallinity confirmed by x-ray diffraction at 50 and 150°C. Thermodynamics analysis of Gibbs free energy, adsorption enthalpy and entropy concluded that all three shales has high affinity to CO2 and lower adsorption enthalpy and entropy compared to CH4. That because of the strong electrostatic attraction between partially negative CO2 molecules and shale clay minerals positive surface cations. Contrary to many studies in the literature, adsorption isotherms fitting demonstrated that adsorption of CO2, CH4 and 10%CO2/90%CH4 on the three shales is multi-layered and best modeled by Freundlich and BET isotherms rather than Langmuir mono- layer isotherm.
CO2-Foam Rheology: Effect of Surfactant Concentration, Shear Rate and Injection Quality
Authors: AlYousif Zuhair , Kokal Sunil , Alabdulwahab Amin , Gizzatov Ayrat
Published: October 2018

Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and sequester CO2 underground. While CO2 injection has been successful, a major challenge facing this technique is enhancing volumetric sweep efficiency. Some of the factors that contribute to this challenge are the low density and viscosity of injected gas relative to reservoir fluids. The use of foam is one of the most promising techniques to increase the CO2 apparent viscosity, thereby improving volumetric sweep efficiency.

Increasing the CO2 viscosity by using surfactants has the potential to mitigate some of the challenges associated with CO2 injection projects. The objective of this work is to investigate the effect of various surfactants on CO2-foam viscosity. Four surfactants were used to evaluate the foam generation and rheological properties of CO2-foams at high pressure and temperature. Dynamic foam viscosity measurements were conducted in a special foam rheology apparatus with supercritical (sc-CO2) under high pressure (3200 psi), temperature (210°F) and salinity conditions. The foam was generated by injecting sc-CO2 and surfactant at different concentrations (0.20, 0.50 and 1.00 wt %), shear rates (10-600 s-1) and qualities (70, 85 and 90%).

The results indicate that all surfactants were able to generate good quality foam at high pressure and temperature. The foam viscosity increases with surfactant concentration. All foams exhibited shear thinning behavior, with foam viscosity decreasing with increasing shear rates. In general, the highest viscosity for each surfactant was reported at the lowest shear rates. The results also showed that the foam quality has an impact on foam viscosity for some cases. The highest foam viscosities for surfactant 2 were achieved at 85% quality. However, the quality had no significant impact on foam viscosity for surfactant 3.
Image Reconstruction of Multiphase Flow Metering: A Compressed Sensing Approach
Authors: Al-Shuhail Shamael A. , Noui-Mehidi Mohamed N.
Published: October 2018

Multiphase flow measurements, based on tomographic imaging techniques, have made substantial progress in the past several years. In particular, ultrasonic tomographic reconstruction has shown its high potential in accurately measuring fluid fractions in a flow cross-section based on direct flow measurements. These types of measurements are very attractive as the system is nonradioactive, has direct contact to fluid, yet without flow obstruction. An ultrasonic tomographic multiphase flow meter (UTM) is being developed to capture the fluid flow rates and phase compositions in producing oil wells. The UTM aims to generate cross-sectional images of the flow inside the pipe. To recover these images, complex computations and high processing time are required, based on a limited amount of available data. For this purpose, compressive sensing (CS) reconstruction methods have shown great potential in overcoming the mentioned data quality and quantity issues. CS builds upon the fact that one can recover certain data of interest from potentially very few measurements. Many CS algorithms have been proposed in the literature. In this paper, we seek to find a suitable algorithm by comparing different CS algorithms in terms of the resulting recovered image quality. Specifically, we survey three algorithms in CS, namely basis pursuit, iterative soft thresholding (IST), and orthogonal matching pursuit (OMP). We also compare the results of the CS algorithms to that of a least-square based conventional algorithm. The numerical results show the superiority of CS recovery algorithms over the conventional approach, both qualitatively and quantitatively. The results also suggest that high image quality could potentially be achieved with less complex CS algorithms, i.e., the IST and OMP algorithms. As presented in the paper, our goal is to adapt CS reconstruction algorithms for images generated by the UTM, for the purpose of accurate quantification of oil, gas, and water phase fractions produced from different wells.
Nanoparticles-Stabilized CO2/Brine Emulsions at Reservoir Conditions: A New Way of Mitigating Gravity Override in CO2 Floods
Authors: AlYousif Zuhair , Almobarky Mohammed , Schechter David
Published: October 2018

CO2 injection is an effective method for enhanced oil recovery (EOR). However, the efficiency of CO2 is hindered by mobility problems. The high mobility of CO2 compared with the reservoir fluids may lead to early breakthrough of CO2, resulting in an incomplete sweep. The use of surface modified nanoparticles has provided an excellent alternative to generate a stable CO2/brine emulsion for CO2 mobility control. The objective of this work is to investigate the effect of: emulsion quality, shear rates, salinity, pressure, nanoparticle concentration and nanoparticle size on the strength of the emulsion.

Glass beads as a porous medium and a capillary tube to measure the apparent viscosity were used to perform the tests at reservoir conditions. Three types of coated silica particles were used to conduct this study. Three qualities were tested: 50, 70 and 90%. Also, five shear rates were used to assess the strength of emulsions. Solutions with 1, 3 and 8 wt% of NaCl were used. The role of the nanoparticle size was also tested for one type of silica particles. The effect of these parameters was evaluated at high pressures (800 and 1800 psi) and temperature (50°C).

For all tested materials, the quality of the emulsion was found to be an important parameter for emulsion strength. Emulsion viscosity increases as quality decreases, which indicates that the strongest emulsion was achieved at 50% quality. For silica partially modified with methylsilyl, the results showed that the change of salinity has no effect on emulsion viscosity. However, the increase of salinity produced emulsions with higher viscosities for silica modified with Polyethylene glycol (PEG) and silica modified with an appropriate material. The shear rate has a significant impact on the behavior of the emulsion for silica modified partially with methylsilyl group and PEG. Also, the study showed that the change of nanoparticle size has no effect on the emulsion strength. The change in pressure, however, has a significant impact on the emulsion viscosity.

The use of nanoparticles to stabilize CO2/brine emulsion has the potential to mitigate the gravity override challenge in a CO2 flood. Long-term stability of nano-particle stabilized emulsion is a critical factor in selecting the appropriate emulsifying agent. This work improves our understanding of the effect of different parameters on the strength of emulsions which can be used to control CO2 mobility and, therefore, improve sweep efficiency.
Experimental Investigation on Co-Polymer Grafted Bentonite for Controlling Reservoir Conformance
Authors: Ahmed Abdelazim Abbas , Saaid Ismail Mohd , Ahmed Afaque , Hamza Mohammed Falalu , Umar Abubaker Abubakar , Aini Siti Qurratu'
Published: October 2018

A water-disperible particulate system has been widely used in many mature oilfields for reservoir conformance control. This paper discusses performances of a newly formulated grafted bentonite to reduce the permeability and build up flow resistance in highly permeable water channeling zones. In this study, effects of various salinities, different injection flow rates and shear rates were investigated in the laboratory to determine permeability reduction ratio and transport properties to improve reservoir conformance problems. A flow model was set-up using sandpack flooding system where the sandpacks were saturated with brine. Experimental results obtained revealed that the grafted bentonite is easily injected and gradually built flow resistance by particles straining, physical-chemical attachment, and swelling. The permeability reduction ratio increased with increasing salinity while it decreased with increasing velocities. A significant permeability reduction ratio was observed when 0.5 pore volume of grafted bentonite dispersed in 1% NaCl brine was injected into brine saturated sandpack column. These significant results highlighted new insights for successful applications of modified bentonite to improve reservoir conformance problems.
Determinations of Engineers Turnover Working for National Oil and Gas Companies in Egypt
Authors: Farahat Abdallah
Published: October 2018

In Egypt, during the past 20-year national petroleum companies has been facing high turnover among experienced engineers who leave without enough notification period. This caused a lot of technical, managerial problems, increase replacement cost, and nonproductive time. The paper purpose is to introduce a new frame work to study and control turnover and/or turnover's intentions of employees working in oil and gas industry especially public and joint venture sectors in Egypt.

The study presents studied various models of turnover in general and focuse on recent devoted models and studies developed for oil and gas industry especially countries with similarities in culture and employees' attitude like Egypt. This will help decision makers to ensure organization stability and performance.

The research introduces a model that is suitable for oil and gas industry, it suggests that job fit, alternative job opportunities and organizational factors are the most significant independent factors that affects turnover. In addition to moderating factors that influence the relationship between the turnover and the said independent factors like: job stress, organization culture, oil prices, managerial style, and payment and rewarding system.

This frame work is a seed for understanding turnover phenomenon, it may be applied in similar industries with the same characteristics like harsh working conditions. The proposed frame work shall help managers, decision makers and researchers to better understand turnover causal factors in gorilla industries like oil and gas.
Use of Advanced Process Control for Automating Conventional Oilfield Operations
Authors: Patel K. , Bakhurji A. , Salloum H. , Kim H. , Winarno M. , Mubarak S.
Published: October 2018

With the proliferation of Internet of Things (IoT) technology and IR4.0, digital information is becoming more integrated into our daily operations. Such a modality of operation allows all disciplines in an organization to collaboratively manage and operate their assets to achieve the maximum value of their assets. In this paper we describe one of the initiatives under the company's digital transformation strategy. It is a simple yet innovative application of Advanced Process Control (APC) that facilitates continuous optimization of the performance of Electric Submersible Pumps (ESP), to not only comply with the assigned production targets, but also to automatically meet the operational constraints. The successful implementation of this technology on multiple oil wells in an onshore oilfield has demonstrated significant power saving, and is expected to minimize premature failures and extend pump life.
An Integrated Study Focusing on Baffle Characterization and Development Optimization
Authors: Liu Shuangshuang , Wei Chenji , Gao Yan , Li Yong , Luo Hong , Liu Zhuo , Xiong Lihui , Zheng Jie , Lou Yuankeli
Published: October 2018

The Middle East carbonate reservoirs are mostly reef flat sedimentary complexes, which are high heterogeneous and have extensive baffles. It brings great challenges to the efficient development of such reservoirs. Focus on the problem, a method of describing baffle distribution conjunctively using static and dynamic data is put forward in this paper. The distribution of baffles in the target formation is characterized based on core observation, well loggings, image logs, etc. Then, their impact towards reservoir performance is evaluated based on production data and dynamic surveillance data. Based on the study, it is acquired that cementation mainly controlled the upper baffles and compaction controlled the lower. Generally speaking, permeability of baffle is higher in the crest area and lower in the flank area. Baffles are stably distributed throughout the reservoir, although their ability to block fluid flow varies from region to region. The existence of baffles and their ability to block fluid flow had impact to the development effect, so development optimization and scheme comparison carried out. The corresponding development strategies are proposed for reservoirs with extensive baffles. Injectors and producers with highly-deviated well-type will help establish effective displacement system and achieve better reservoir production, it can improve the development effect and enhance oil recovery. This study offers a comprehensive case study for engineers and geologists to better understand this reservoir, it also provides a methodology that can be referred when developing similar fields.
Innovative Mechanical Tapered Scab Liner Design and Deployment to Restore Well Integrity
Authors: Aljubran M. J. , Ombe E. M. , Alluhaydan A. S. , Thomas S.
Published: October 2018

The current oil and gas industry uncertainty encourages innovative, efficient, and simple drilling and workover solutions. Challenging and problematic formations cause various design complications and operational risk. These include lost circulation, well control incidents, high density drilling fluid systems, tool design limitations, etc. Such troubles can also lead to liner and casing leaks downhole and eventually undesired surface pressure buildups across the tubing-casing and casing-casing annuli.

The case study well was drilled and completed, but prior to production a tubing-casing annular pressure of 6,500 psi was recorded. With two liners in the well casing designs (4-1/2 in. and 7 in.), a well leak was suspected to be at the top of the 7 in. liner as it was laying across a deep and over-pressurized formation with a 152.5 pcf gradient. After commencing the workover operations and due to downhole leaks and washouts, the well had to be killed off-bottom with 160 pcf manganese tetroxide (Mn3O4) mud. The well was fully decompleted, except for the production packer, which was left in hole. Investigation and diagnostic operations showed leaking 7 in. liner body and liner top packer.

To repair the leaking 7 in. liner, the team introduced an innovative design with a 4-1/2 in. x 7 in. tapered scab liner to sting into the newly installed repair packer and extend above the existing 7 in. top of liner to set on the 9-5/8 in. casing, and so cover the leaks. A mechanical 7 in. x 9-5/8 in. hanger and liner top packer system was deployed to allow for cementing the scab liner then setting these mechanical tools, where hydraulically actuated systems were impractical. Due to the high kill mud density of 160 pcf, a special 165 pcf Mn3O4 -Hematite cement recipe was adapted. Despite the high slurry density, this formulation allowed for optimal mixing, pumping, and leak isolation operations.

This paper will highlight the case study well history and challenges leading to liner leaks while emphasizing the nature of the over-pressurized formation. It will demonstrate the mechanical tapered scab liner design and deployment procedures in comparison to the conventional scab and tie-back liner jobs.
Molecular Transport of Solutes and Ions Through Filter-Cake: Implications for Wellbore Instability and Formation Damage
Authors: Adewole Jimoh K. , Kazeem Taye S. , Oyehan Tajudeen A.
Published: October 2018

During drilling, the invasion of drilling fluid components into the formation can be a major source of operational challenges such as borehole instability and formation damage. Filter cake, which is formed by particles that are captured near the wellbore surface, allows the movement of some molecules while it restricts the others. The properties of the filter cake as well the composition of the filtrate which permeate through it are very important parameters that can be tuned to prevent possible operational challenges. In this paper, the transport properties of certain ions (sodium, potassium, magnesium and calcium) through bentonite- based drilling fluid filter cake were investigated. The effect of in-house activated clay particles on the transport properties was also investigated. The capability of the cake to control the transport properties of the permeating ions were measured in terms of ion rejection. The results obtained for the pure bentonite follows the sequence: Ca2+ > Mg2+ > K+ > Na+. The trend was however, reversed by the addition of the activated clay to Mg2+ >Ca2+ >K+> Na+. The avearge rejection for the pure bentonite cake for Na+, K+, Mg2+ and Ca2+ are 4.45, 49.64, 53.33 and 94.43%, respectively. The rejection results for the mixed-matrix cake containing the activated clay were 6.38, 51.34, 86.19 and 78.09 for Na+, K+, Mg2+ and Ca2+, respectively. It was observed that the selectivity of the filter cake for Mg2+ and Ca2+ was reversed due to the addition of the activated clay.
Propped Fracture Conductivity in Shale Reservoirs: A Review of Its Importance and Roles in Fracturing Fluid Engineering
Authors: Elsarawy Ahmed M. , Nasr-El-Din Hisham A.
Published: October 2018

Shale oil and gas developments have been growing dramatically in the U.S. since the successful development of the Barnett shale in the early 2000's. The industry was able to unlock the Barnett shale by coupling the technologies of both horizontal drilling and hydraulic fracturing. The experience stimulated the spread of this method to other fields which eventually led to the recent U.S. production boom. However, numerous underperforming wells draw attention to the importance of completion optimization to maximize hydrocarbon production from shale reservoirs. Several approaches for completion optimization have been developed; however, fracture conductivity is usually sacrificed to minimize the operational cost. The objective of this paper is to provide a comprehensive review that highlights the importance of fracture conductivity to hydrocarbon production from shale reservoirs and its potential roles in the fracture design process.

The reviewed simulation, laboratory, and field studies reveal the importance of improving fracture conductivity to maximize the reserve and well production performance in different shale formations. Reliance of well production on fracture conductivity is explained by its severe reduction at downhole conditions, in addition to, the improved effective formation permeability by the effect of the induced microfracture networks. The factors affecting the fracture conductivity at downhole conditions and its calculation complexity are explained.

The review also demonstrates the adverse effect of water on fracture conductivity in shale formations, through shale softening and proppant embedment mechanisms. The different approaches to select the fracturing fluid additives for an improved fracture conductivity are summarized in this review. To minimize the damage to the formation and the fracture conductivity, the use of water-alternative energized fluids is discussed.

This paper improves the understanding of the main factors affecting the success of shale hydraulic fracturing treatments. Hydraulic fracturing is the main key to ensure an optimum completion process which helps to maximize the production from unconventional shale oil and gas reservoirs.