bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nanoengineered Cement for More Effective Remedial Cementing Jobs
Authors: Tabatabaei Maryam , Dahi Taleghani Arash 
Published: October 2020

Abstract
The success of remedial cementing jobs is crucial, as its failure, not only may further damage the well, but also may lead to the total loss of wellbore. Therefore, it becomes necessary to develop reliable technologies to make these treatments operationally and economically more effective. Obviously, more effective cementing materials would improve the chance to address any integrity issues related to presence of microannulus. We present a novel solution by engineering the cement at the material scale to carefully adjust its rheology and mechanical properties to sneak into narrow opening and develop stronger bonding with pre-existing cements. We seek for better penetration into narrow spaces behind the casing with appropriate thickening time, low set-cement permeability, and high strengths. The outcome could provide an economic solution although involved with manipulating cement properties at the molecular scales.
Automated Solids Content Determination in Drilling and Completions Fluids
Authors: Gul Sercan , Karimi Vajargah Ali , van Oort Eric , Leulseged Amare , Cayeux Eric 
Published: October 2020

Abstract
Monitoring of low- and high-gravity solids (LGS and HGS) content and maintaining these at ideal levels is essential for the optimum drilling fluid performance, efficient hole cleaning and ECD management, as well as preventing failures of surface and downhole equipment during drilling. LGS and HGS monitoring in the field is currently accomplished using the API retort measurement, which has certain drawbacks and is difficult to automate. In this paper, alternative approaches to solids characterization are presented that lend themselves much better to automation and real-time monitoring.
Two new approaches were investigated to automate the LGS and HGS content measurements of drilling fluids, which can potentially replace the retort test in the future. In the first approach, extensive lab experiments were conducted to generate a controlled dataset that includes fluid rheological properties and density changes by the addition of various levels of LGS and HGS. Using this dataset, multi-linear, Ridge, Lasso, K-nearest neighbors (KNN), and Random Forest (RF) regression models were trained and tested to predict LGS and HGS content of drilling fluids. A key advantage of this machine learning (ML) approach is that these fluid properties can be obtained in real-time with measurements that are relatively simple and easy to automate. In the second approach, X-Ray Fluorescence (XRF) was used to generate calibration curves for various common solids used in drilling fluids (i.e., barite, clays, salts). This method also lends itself well to automation with real-time inline measurement.
Side-by-side tests of various fluids were performed using the API retort measurement, the ML approach, and the XRF sensor. It was observed that the API retort measurement can provide erroneous LGS and HGS content estimations. On the other hand, the trained ML regressor provided results with an average absolute error of only 0.3%. It was also observed that with the XRF measurements, distinct solids can be tracked highly selectively by quantifying the concentration of their specific elemental compounds (i.e., barium for barite concentration, silicon for sand concentration, iron for clay concentration). A detailed comparison of the three methods (API retort, ML, and XRF) is provided, clearly showing the advantages of the ML and XRF approaches over the older retort method.
The technology described here opens the doors to automated mud monitoring, maintenance, and solids control operations, which can assist with real-time solids content management and optimization. This will benefit downhole ECD management, hole cleaning optimization, ROP improvement and reduced equipment failure, resulting in safer wells drilled at lower costs.
Experimental Analysis of Alkali-Brine-Alcohol Phase Behavior with High Acid Number Crude Oil
Authors: Magzymov Daulet , Clemens Torsten , Schumi Bettina , Johns Russell T. 
Published: October 2020

Abstract
A potential enhanced oil recovery (EOR) technique is to inject alkali into a reservoir with a high total-acid-number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT). The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil, while also avoiding formation of gel/viscous microemulsions.
This paper investigates the potential field application of injecting alkali to generate in situ soap and favorable phase behavior for a high TAN oil. Oil analysis results show that the acids in the crude are a complex mixture of various polar species and not mainly carboxylic acids. Phase behavior experiments show that the system does not undergo typical Winsor microemulsion behavior. Therefore, traditional microemulsion models can cause unreliable recovery estimates. The mixing of alkali and crude/brine can generate water-in-oil macroemulsions that are highly viscous instead of forming the classical Winsor types. Good core flood recovery cannot be explained by the formation of a Winsor microemulsion phase, as is expected in surfactant EOR, mainly because these macroemulsions form before such idealized phase behavior can occur. A substantial decrease in interfacial tension is observed without the formation of a viscous phase in a narrow window of alkali concentration. Corefloods with polymer perform well in this concentration range, although incremental recovery could be overestimated some owing to increased water solubility in oil within these macroemulsions.
The viscous phase behavior at large alkali concentrations is likely explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.
Unique Real and Relevant Time Formation Evaluation: A Case Study from the Gulf of Mexico with Innovative Advances in Logging While Drilling
Authors: Kenning Kevin , Parker Jay , Murray Roger , Durrant Jeff , Watcharophat Hathairat , Vallega Valentina , McCall Rory , Shrivastava Chandramani 
Published: October 2020

Abstract
This case study presents a success story of a development well in the Gulf of Mexicodrilled with oil-based mud, with latest high-definition borehole image and comprehensive formation evaluation-while-drilling suite. Historical data from multiple offset wells suggested that the standardresolution petrophysical logs were insufficient to accurately evaluate this low-resistivity, low-contrastreservoir. The presence of salt intrusions compromises the surface seismic interpretation and poseadditional geological challenges, adding uncertainty to the oil water contact—which, if incorrectlyidentified, would cause early water production and compromise the success of the well.
Deploying a unique, high-resolution dual-physics imaging-while-drilling system and the advanced petrophysical LWD logging suite for the first time in this field was critical toachieving the optimal reservoir characterization and making subsequent operational decisions. Real-timecapture-spectroscopy and sigma measurements were essential to evaluate the mineralogical compositionand saturation estimation. Water saturation computed from sigma gives an estimate of free- and bound fluid volume, independent of the resistivity measurement, which showed little contrast betweenhydrocarbon- and water-filled formations.
The real-time transmission of apparent resistivity images enabled the identification and interpretation of the low-resistivity low-contrast reservoir, which appeared to be comprised of cross-bedded, sand-silt laminated facies. High-definition borehole images detected features such as fine lamination and fractures, which were not possible to be identified with the standard-resolution logging suite previously deployed in this field. This information provided an insight into the reservoir architecture and possible extent of the depositional facies vertically and laterally. The ultrasonic high- and low-frequency borehole images further helped refine the understanding of reservoir architecture in relevant time to aid in completion design. Additionally, the apparent resistivity derived from the high-definition resistivity provided a proxy to ultra-shallow resistivity that was able to identify the movable fluid in the reservoir when compared to standard resistivity measurements in singular drilling pass and confirmed the oil-water contact which were a critical information for well completion design
This case study demonstrates the integration of petrophysics and geological interpretation of comprehensive LWD logging which has been fundamental to resolve the reservoir characterization uncertainties and optimizing the completion strategy in a challenging low resistivity reservoir in one drilling run with real-time transmission of high-quality data.
Managing to Bring Appropriate Full Field EOR Production Profile Into Decision Making of Field Application From Notional Stage
Authors: Yonebayashi Hideharu , Iwama Hiroki 
Published: October 2020

Abstract
Full field production profile is needed to evaluate enhanced oil recovery (EOR) option and to progress the EOR project. In general, the methodology of full-field profile estimation highly depends on the objective case: field development maturity level, technology readiness level of the EOR option to be planned, etc. Therefore, this paper is facilitating how we should select an adequate methodology to estimate full-field EOR profiles through comparison of four case studies.
Case-1 was picked up as an example of type curve method based on sector models for water alternating gas (WAG) application using CO2 or hydrocarbon miscible gas. Case-2 represented a full-field simulation approach to incorporate facility capacities into account adequately because of produced gas re-injection (i.e. gas EOR). Case-3 demonstrated to use the identical flow model, which was history-matched with long production records, for estimating a new CO2 foam EOR technology which was unavailable as option in the identical commercial simulator. The last Case-4 dealt an emerging microbial EOR/EGR process without any commercial simulator and no pilot data yet.
In Case-1, two type curves were generated to represent typical geologies in the objective field: homogeneous and heterogeneous areas. After sensitivity studies using the simple sector models to optimize each parameter, type curves were obtained from the detailed sector models. The type curves, assigned in corresponding areas, were summed to estimate full-field profile. In Case-2, even full-field simulation is debatable in general due to huge workload and computation, it still has important role to evaluate gas EOR with limited gas processing capacity because to ignore the facility limits might mislead to optimistic conclusion. In Case-3 in the mature field, the history-matched model was already established by a commercial simulator. Unfortunately, the simulator does not have an exact option to evaluate our emerging CO2 foam technology while available for the conventional foam EOR using surfactant as foaming agent. Thus, we managed to handle our EOR technology by matching laboratory experimental outputs with pseudo-calculated gas mobility reduction ratio. In Case-4, another emerging microbial EOR technique was estimated analytically even only laboratory experimental data was available. Any commercial simulator is not available, either. The unique approach took essence of experimental outputs into a well type curve, and then full-field profile was estimated.
Each workflow has pros/cons, and an adequate one should be selected. However, in usual, a unique workflow is just applied to estimate full-field profile in the evaluation of objective EOR option. Furthermore, there has been little discussion of workflow selections from the aspect of development stage, EOR technological emerging level, and evaluation tool availability. This paper can provide ideas to consider guidelines for generating full-field profiles.
Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya
Authors: Masoud Mohamed , Meddaugh W.Scott. Scott , Masud Masud Eljaroshi 
Published: October 2020

Abstract
Reliable and representative models and detailed characterization of a geologically complex reservoir are crucially important in having better understanding of the reservoir behavior and directly guiding to the most efficient implementation of the field development plan. This study focused on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The goals of the study were to characterize the vertical and lateral spatial continuity of each of the three formations and to calculate deterministic and probabilistic volumetrics.
The Meghil Field, discovered in 1959, is located on the Zelten Platform and regionally classified as an extensional area of the larger Zelten field. Nineteen wells were drilled targeting the primary reservoir interval of interest at a drilled depth of around 8000 feet. A 3D seismic program was conducted to develop detailed structural maps for the Kalash and Waha/Bahi/Gargaf formations to evaluate future gas field development program. The field is characterized by three slightly asymmetrical anticlinal traps trending NW-SE. Major and minor faults that cut the interior of the structure were detected in the seismic block. The available drill stem DST and production tests were used to evaluate the level of communication between the structures. The structural framework for a 3D reservoir model is based on the interpretation and integration of the seismic volume and the available well logs.
The well log data show that the net hydrocarbon bearing zone thickness is about 270 feet, the average porosity ranges from 4% in the Bahi/Gargaf sandstone to 13% in the Waha limestone. The average water saturation ranges from 15% to 32% in the Waha limestone and the Bahi/Gargaf sandstone respectively. Geostatistical models were developed using the well log and core data along with the structural model developed from the 3D seismic volume. The models suggest that porosity decreases towards the flanks and that separate flow units are likely present. The deterministic and stochastic give estimates of the original gas in place of about 830 Bscf and 732.2 Bscf for the upper and lower reservoir intervals, respectively. This study demonstrated the potential for significant additional hydrocarbon production from the Meghil field as well as the potential impact of heterogeneity on well placement and spacing.
Successful Mitigation of Fracture Hits in High-Pressure Stimulation using Bottomhole Gauges and an Optimized Engineering Design, Offshore Black Sea
Authors: Grubac Gabrijel , Patrascu Radu , Janiczek Peter , Kolasa Bartlomiej 
Published: October 2020

Abstract
This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. A multi-faceted approach in applying lessons learned and pre-job geo-mechanical analysis of depletion-induced stress differential and its effects on fracture interactions will be discussed. Details of on-the-job, real-time bottom-hole pressure monitoring of nearby wells, with the effort of on-the-fly pumping schedule changes, will also be provided.
An analysis was conducted on past fracture interactions observed from multistage stimulation jobs in the area. Depletion, distances between producing wells, and a stress analysis was performed using fracture simulation software, and a consequent analysis of fracture geometry was applied. A bottom-hole gauge pressure profile assessment of nearby wells, including the pre-stimulation, shut-in, and post-stimulation period of the targeted well, was completed. A redesigned treatment was applied, considering a mitigation plan for potential on-the-fly changes during pumping. A holistic tracer analysis of production contribution between stages and wells was performed, with the goal of understanding possible crossflow of production fluids.
Past-fracture interaction events have been analyzed, and clear drivers for fracture hit communication were observed. Extreme depletion effects were a primary factor in enabling fracture communication. The preferential fracture growth was further enabled owing to the continuous production of nearby wells and no shut-in implementation. The 3D geo-mechanical model was built using pertinent data from the targeted and nearby wells. The model was further optimized using fracture geometry outputs, and constraints were input to limit the fracture growth and avoid communication. The outcome of the analysis showed a clear driving force behind the interactions was depletion. An on-the-job assessment of diagnostic tests yielded a heterogeneous behavior of the horizontal segment, further proving stress differentials along the lateral. An overall chemical tracer analysis of the targeted and nearby wells was completed using pre- and post-stimulation fluid samples. The results were crucial in understanding the stimulation approach and possible crossflow effects due to fracture communication. Additionally, using bottom-hole temperature readings, a rudimentary cool-down and heat-back analysis was performed to better understand possible fluid interactions with nearby wells and optimize fluid design.
Intra-stage fracture interference presents unique events and challenges that are typically managed on a case-by-case basis, and this work presents the critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with wells in close proximity.
New Developed Mathematical Model for Predicting Viscosity Profile and Proppant Transport Utilizing HVFRs Dosage with Produced Water
Authors: Ba Geri Mohammed , Noles Jerry , Kim Sangjoon , Ellafi Abdulaziz 
Published: October 2020

Abstract
Switching to utilize HVFRs has been blossomed rapidly due to enormous advantages such as the ability to carry proppant and high potential lower cost. However, challenges remain in fracking fluids rheology characteristics due to a change in water quality that leads to poor proppant transport through fractures. The primary objective of this study is to develop a mathematical model based on prior published experimental data that can be used to predict HVFRs viscosity profile as a function of essential factors.
Water analysis and viscosity property characterization of the selected fracturing fluid (HVFR) were investigated to address the effect of water quality on proppant transport behavoir. In this paper, a case study of the Permian Basin produced water "high-TDS (125Kppm)" was chosen in screening criteria analysis. Also, different dosages (0.25, 0.5, 0.75, 1.0, and 2.0 gpt) of HVFRs were selected to estimate the viscosity profile in freshwater and the Permian produced water.
The developed new model from this study can be used effectively to predict viscosity profile and proppant transport in HVFRs fluids taking into account fracture fluid dosage, water quality, and operation shear rate. The developed model covers HVFRs dosage ranging from 0.25 to 2.0 gpt (gallons per thousand gallons). This model can be used to assist in obtaining proppant settling velocity as a function of shear rate. The developed model shows the high accuracy of prediction HVFR viscosity profile with a low average error of 0.14% and 0.07% in freshwater and Permian produced water, respectively.
This paper will help provide a full understanding of the distinct changes of the mechanical characterization on the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-salinity conditions effect, which could be used as guidance for fracture engineers to design and select the optimum dosage of friction reducers.
Stimulation Fluid Advancements Improve Gas Production from Low Temperature Turonian Siltstone
Authors: Olennikova Olesya , Loginov Arkadii , Yudin Alexey , Vorobyev Vladislav , Mazhirin Yury 
Published: October 2020

Abstract
The Turonian siltstone found throughout the Siberian region in Russia is laminated, heterogeneous, and shaly; has permeability of 0.1 to 3.0 md; and contains hundreds of trillions cubic feet of natural gas. Hydraulic fracturing is necessary to achieve commercial production rates. Important developments have been made in optimizing a water-free fracturing fluid that can be used in similar cold and highly water-sensitive reservoirs worldwide.
The study encompassed laboratory testing methodology, testing results, and field trial campaign analysis of the advanced water-free fracturing fluid. Non-Newtonian fluid rheological behavior, proppant transport ability, and fluid break under dynamic and static conditions at 60°F (15°C) were investigated and compared to conventional crosslinked water-based fracturing fluids. The field trials used a fluid recipe that enabled successful execution of very aggressive fracturing designs using large-size proppant placed at concentrations of up to 12 lbm/gal added (1400 kg/m3) in multistage fracturing treatments along a horizontal wellbore. This approach was used to improve fracture conductivity and fracture cleanup while minimizing fluid costs.
The most significant advancements have been made in the breaker package design for the fluid mixed in diesel fuel. Improved breaking can accelerate the flowback period and create a high-retained-conductivity proppant pack, allowing large volumes of gas to flow with minimal restriction. Additional study of proppant transport revealed the presence of elastic properties that are not common for water-based guar-borate gels. This property enabled increased proppant concentration and aggressive hydraulic fracturing designs that were successfully employed in a field trial campaign comprising three horizontal wells completed with a total of 10 fracturing operations. Multistage fracturing completions consisted of shifting sleeves for the fracturing stages and separate ports with screens for the production stage to control formation and proppant flowback. This completion enabled selective fracture cleanout, which is vital in the low-temperature geological conditions. The developed stimulation approach resulted in progressive gas production increases after stimulation.
Fluid development results indicate the new diesel-based fracturing fluid delivers an improved stimulation approach for low-temperature siltstones containing a high content of sensitive clays. It is the only project we have seen in the literature with a successful diesel-based fracturing fluid application in extremely low-temperature geology. Although developed for Russian fields, the work is equally applicable to any water-sensitive, shaly, low-temperature reservoir globally.