bluuebunny/crossref_metadata_2025_split huggingface dataset:
Surfactants Impact on CO2 Sequestration for Enhanced Gas Recovery and in Depleted Carbonate Reservoirs
Authors: Eliebid Mohammed , Mahmoud Mohamed , Shawabkeh Reyad , Elkatatny Salaheldin 
Published: November 2017

Abstract
Indiana limestone cores were crushed and sieved to particle size of 125-250 microns, half of the sample was kept pure and the remaining has been treated with NaCl brine containing 0.1% (VES) viscoelastic surfactant to study the effect of surfactant on CO2 and CH4 adsorption. The carbonate rock was characterized using X-ray diffraction to determine the crystallinity. The adsorption measurement has been conducted at 50, 100 and 150°C and to 45 bars maximum pressure. At 50°C, adsorption uptake of CH4 and CO2 for untreated samples was higher than VES treated samples. However, at 100 and 150°C Both CH4 and CO2 adsorption capacities of untreated limestone was considerably lower than VES treated limestone. Thermodynamic studies indicate that adsorption on untreated samples was exothermic with ΔHads of -16.7 and -13.5 KJ/mol for CH4 and CO2 respectively and spontaneous adsorption at 50°C. In contrast, adsorption of CH4 and CO2 is endothermic with corresponding ΔHads of 60.1 and 36.2 KJ/mol and spontaneous at high temperatures. through all measurements CO2 adsorption was three times CH4 adsorption uptake due to high affinity between CO2 and calcite. Adsorption isotherms fitting shows that Freundlich isotherm is the best model to represent the adsorption behavior for all conducted experiments at all temperatures with lowest sum of squared errors (SSE) and highest R2. These results suggest that previously treated carbonate reservoirs that has mid-high temperatures has great adsorption potential for CO2 and CH4 making them an excellent candidate for CO2 sequestration.
Validation of a Workflow for Digitally Measuring Relative Permeability
Authors: Jerauld Gary R. , Fredrich Joanne , Lane Nathan , Sheng Qiang , Crouse Bernd , Freed David M. , Fager Andrew , Xu Rui 
Published: November 2017

Abstract
This paper provides a validation of a Digital Rocks workflow for computing relative permeability from micro-CT images of rock using Lattice Boltzmann simulation. The workflow has the potential to dramatically reduce the time and cost of measuring relative permeability by experimental techniques. Additionally, this workflow utilizes smaller volumes of rock than traditional laboratory techniques enabling the possibility of using side-wall cores and a further reduction in costs by avoiding costly coring operations.
The approach taken is to construct computational grids from segmented micro-CT images to define the pore space available for fluid flow, to run two-phase Lattice Boltzmann simulations, and derive relative permeability from the computed flow fields. Strategies for simulating both steady-state method and unsteady-state method relative permeability protocols are discussed. Five distinct stages of validation are described beginning with idealized 2-phase benchmark studies, progressing to physical micromodel experiments with a range of wettabilities, physical flow experiments in 3D grain packs with differing wettabilities, trapped gas measurement on sandstones with demonstrated dependence of trapped gas on pore structure, and finally corefloods on reservoir rocks.
The simulations quantitatively reproduce the displacement fronts and residual fluids distributions seen in physical experiments, and observed relative permeability behavior in coreflood experiments. Simulations of 2½-D micromodels reproduce the experimentally observed invading water front shape along with quantitatively matching residual oil saturation for the full range of wettabilities modelled; from water-wet to oil-wet. Importantly, simulations accurately capture the enhanced sensitivity of residual oil to intermediate wettability exhibited in the micromodel experiments. Residual oil trends for a range of 3D sandpacks of controlled wettability are predicted by simulation. The dependence of trapped gas on pore structure for Fontainebleau sandstone is reproduced quantitatively. And finally, simulations of relative permeability for reservoir rock for a range of plausible wettabilities are shown to be consistent with the results of laboratory measured relative permeability for reservoir rock from the same plug.
Preventing Failures In LDPE Plants Caused By Vibrations And Pulsations Of Reciprocating Compressors
Authors: Carcasci Cosimo , Sacco Marco 
Published: November 2017

Abstract
One of the main causes of damages and failures in industrial plants is the vibrations of related equipment; reciprocating compressors are particularly subject to vibration-related phenomena due to the operating nature of its moving part: alternating forces and pressure pulsations are in fact direct and inevitable consequences of their behaviour.
Particular care must be paid, during the design stage, regarding the interaction between the compressor and the plant as a whole to avoid that vibration problems may also arise after a machine has been installed.
The paper will describe a case that occurred in a polyethylene plant, where high piping vibrations resulted in ruptures, welding failures and hazardous gas leakages.
After a detailed root cause analysis of the failures, new more effective supports were studied and the exact positioning of the supports was decided, based on the results of a dynamic forced-response FEM analysis. The vibration measurements were used to locate the problems but also to tune the model, and subsequently to identify the key points where a stiffer structure could have been more effective. Consequently, many of the existing supports were reinforced and additional supports were added, with high damping fabric pads between the supports and the piping, in order to further reduce the impact of the vibration. Finally, also the cooler structure and foundations were reinforced.
Unique Cost Saving Solution Applied in Tight Gas Field in Sultanate of Oman to Mitigate Corrosion and Well Integrity Damage
Authors: Abdul-Majid Imran , Ayotunde Ajayi , Shihab Balushi , Abdullah Shuely , Blessing Oguni 
Published: November 2017

Abstract
This paper demonstrates an application of failure prediction and a cost effective solution to integrity problems of safety critical elements in wells in a high pressure, high temperature (HP/HT) gas field. Lekhwair field is a gas development in Northern part of the Sultanate of Oman producing approximately 2.8 MMSM3/D from the Upper Mafraq (UM) formation and Lower Mafraq (LM) formation. The LM formation has CO2 content in the range of 2-5 vol% which requires all the Lekhwair wells producing from this formation to be completed with stainless steel (FF) x-mas tree and tubing hangers.
At the onset of field exploration and appraisal, some wells in Lekhwair field were completed with carbon steel (DD) x-mas trees and tubing hanger which is incompatible with the CO2 component of the formation fluid. This has led to severe corrosion in some of wells. Consequently, a x-mas tree retrieval and inspection campaign confirmed the metal loss rate was standing at ~ 5mm/year.
To predict the meantime to failure of the DD tubing hanger and the x-mas tree, a robust stress analysis model was built to determine failure prognosis for the tubing hanger. The model was calibrated with actual data by integrating the measured metal loss observed on the existing x-mas tree after retrieval. This process has been embedded as part of reliability and failure analysis modelling for wells with DD x-mas trees and tubing hangers.
The outcome of the failure modelling showed that the tubing hangers would fail within 3 years if the hanger is consistently flow-wetted. This was used as a basis to develop a well integrity management plan and remediation solution for the Lekhwair wells with DD tubing hangers. To remediate the problem, the conventional solution applied in the industry is to execute a work-over to pull the existing tubing hanger and recomplete the well using the rig at a cost of 2 MMUSD/well with a 50% probability of success. This innovative new solution was devised by the team to execute an intervention using a slick-line unit and installing a through-tubing straddle across the existing tubing hanger to isolate it. This effectively prevents the tubing hanger from being flow-wetted and stops the tubing hanger from further corrosion. The solution has been deployed in the Lekhwair wells, and has been proven to lead to a cost and time saving in excess of 1.5 MMUSD/well and 10 days rig time, respectively.
Applicability of Managed Pressure Drilling MPD in a High Sulfur Content Fractured Reservoir
Authors: Safipour M. J. , Mavaddat Y. , Mavaddat M. , A'Rabi M. , Kadkhodaei N. , Abdollahi A. , Behbahani S. M. 
Published: November 2017

Abstract
Objectives/Scope: In this study, Managed Pressure Drilling (MPD) is investigated in a naturally fractured Iranian oil field as a tool to mitigate under balanced drilling hazards due to its high Sulfur content; and fluid losses and other problems that are inherent to conventional over balanced drilling.
Methods, Procedures, Process: MPD was identified, planed, and applied in an already drilled well, as an alternative technology, to calculate the increase in its rate of penetration (ROP). The calculations were made by Schulumberger Drilling Office package and quality checked by using Signa ERDS software. The software simulates drilling fluid dynamics to investigate application of drillind hydraulics to better chose the optimum drilling technique. Well drilling fluid properties, bottom-hole assembly, casing/completion design and rock formation properties are implemented as an input to the software to start calculations.
Results, Observations, Conclusions: The subject of this study was drilled in south west of Iran. Drilling experiences in this area identified the rock formation as a brittle, highly fractured, which negatively impacts drilling time and cost. Also, in certain instances, elevated mud weights are required to deal with high-pressure high sulfur content gas and/or water flows. Calculation shows that in shallow depths (0-470.8 ft, dd) due to low pore pressure, drilling mud is in balance and within pressure window. At deeper depths (470.8-7211.3 ft, dd) drilling is MPD and increase in mud pressure is required. At (7211.3-9530.8 ft, dd) depths, sharp changes in reservoir pore-pressure cause different increases in mud pressure (from 90 to 600 psi). At deeper depths (9530.8-13154.5 ft, dd) an increase in mud pressure may cause formation fracture, so it is suggested to continue overbalance drilling or separate the well bore by casing. If the formation is separated in previous section, drilling from 9530.8 to 13154.5 ft, dd, pressure management can be continued with an increase in applied back pressure in order to stop toxic gas hazards. At deeper depths (more than 13154.5 ft) according to high depth and dramatic pressure increase, it is suggested to continue MPD to prevent formation damage or induced fracturing and also prevent H2S influxes into annulus.
Novel/Additive Information: Tts the first time to apply MPD technique in a drilling well design in this filed as a solution to challenging drilling conditions like narrow pressure window, Toxic gas hazards, sever mud loss problems, differential stocking and blow out risks. Such results may result in a significant improvement in drilling economics.
Seismic Reservoir Characterisation for Horizontal Well Planning: A Field Case Study of an Unconventional Upper Jurassic Reservoir Onshore UAE
Authors: Caeiro Maria Helena , Al Kobaisi Abdulla , Neves Fernando 
Published: November 2017

Abstract
Seismic data offer valuable spatial information that contributes to the development strategy, such as drilling decisions and well planning. Inverting 3D seismic reflectivity data to impedance unlocks the potential of using seismic data to estimate the lateral variability and to predict reservoir geomechanical behaviour. The geomechanical model contributes for the evaluation of wellbore stability, frackability and drilling direction. The objective of this work is to illustrate the use of seismic derived models for reservoir and geomechanical properties, such as total porosity, total organic carbon (TOC) and rock rigidity. These properties are instrumental to characterize tight reservoirs and useful tools for defining a horizontal well trajectory.
The study area has an exploration potential of unconventional reservoirs, targeting tight carbonates from Upper Jurassic. To date, only one well has been drilled in the area of the interest and high quality 3D seismic data is available. The process consists of conducting seismic inversion, using the well and the 3D PSTM seismic data, and resulting in the generation of 3D subsurface impedance model. The well-log relationships between impedance and reservoir quality (effective porosity, source richness) and completion quality (brittleness) were determined and showed high correlation. Hence, 3D rock quality and geomechanical volumes were derived to characterize the behaviour of the reservoir target.
Seismic derived properties models yield a better description of the reservoir heterogeneity than using seismic reflectivity data only. The horizontal well trajectory was planned taking into account the observed and significant lateral variability revealed by the 3D models estimated based on seismic inverted data.
The results obtained using this methodology demonstrate the importance of integrating geophysical characterisation as a relevant supporting factor in the drilling decision making process. In particular, it validates the use of seismic derived reservoir and completion quality models as an additional tool in the definition of a horizontal well trajectory in a tight/unconventional deep gas target.
Forecast Of Ultra-Shallow Three-dimension Horizontal Well Extension Limit
Authors: Lulin Kong , Ye Tao , Xinyun Liu 
Published: November 2017

Abstract
Objectives/Scope: The length of horizontal section has a direct effect on heavy oil development efficiency. In order to calculate the extension limit of ultra-shallow horizontal wells in Venezuela heavy oil reservoir and provide theoretical reference for reasonable horizontal well design, this paper analyzed extension ability of ultra-shallow large displacement horizontal wells and give the reasonable extension length of horizontal section and reasonable drilling platform arrangement.
Methods, Procedures, Process: Analyze the main factors that impact the horizontal section length in heavy oil formation. Calculate the friction coefficient through measured data. By optimizing the well trajectory and BHA, establishing models for predicting torque and drag of horizontal wells and analyzing hydraulic parameter effect on extension ability of long horizontal section wells, the author calculate the mechanical extension limit and hydraulic extension limit of horizontal wells.
Results, Observations, Conclusions: Comparing the two extension limit, we find that ultimate extension length of horizontal section is mainly constrained by torque and drag. thereby the safety maximum extension length of horizontal section in heavy oil is predicted accurately. On this basis, we put forward a new interleaving well spacing design.
Novel/Additive Information: The result of this paper can provide theoretical reference for reasonable horizontal well trajectory design and horizontal length design. The novel interleaving well spacing design can help reduce the dead oil area significantly and increase the controllable reservoirs, which is of great importance to oil operator.
Optimal Matching of Bit and Reamer for Increased Reliability of Hole-Opening BHAs
Authors: Kueck A. , Ichaoui M. , Herbig C. , Hohl A. , Ostermeyer G. P. , Reckmann H. 
Published: November 2017

Abstract
Mechanical loads in hole-opening BHAs result in tool failures and generate maintenance costs and non-productive time. This paper presents a method to increase the reliability of hole-opening BHAs by optimally matching the bit and reamer. The weight and torque distribution between the bit and reamer is predicted using a stationary load model. New quality load curves facilitate the evaluation of bit-reamer combinations in a user-friendly way. The model and the load curves are validated on a unique set of field data, enabling determination of the model's accuracy.
The model is based on the mechanical specific energies at the bit and at the reamer. The model assumes the RPM and rate of penetration to be constant, the BHA is rigid in the axial and torsional directions and the lateral movement is blocked. Quality load curves are deduced that depict the load distribution in one plot. The model is validated on a unique data set that includes several high-precision measuring tools placed along the drill string. The unconfined compressive strength over depth that usually is not measured in other runs is available. The data set enables precise determination of the axial forces and torques directly at the bit and at the reamer. The observed mechanical specific energy, drilling efficiency, and aggressiveness of both cutting tools over depth are measured.
The model and the quality curves are used to predict the weight and torque distribution depending on the formation type at the bit and at the reamer. A comparison of the prediction to the measured data shows that the weight distribution is predicted with an error of 2% and the torque distribution is predicted with an error of 10.8%. The model accuracy is determined by introducing uncertain parameters into the model. The load predictions are again compared to the measured data. Using the coarse parameter set, the mean prediction error increases to 13%, which is very good, considering the simplifying assumptions of the model.
The validated model and the new quality curves enable an optimal choice of bit and reamers. The presented approach is fast and user-friendly and perfect for an application in advisory software in the well-planning phase. The increased reliability due to less mechanical overloads leads to reduced maintenance costs and less non-productive time of the reamer BHAs.
The Study of Nanosurfactant EOR in Carbonates by Advanced NMR Technique
Authors: Al Harbi Ahmad M. , Gao Jun , Kwak Hyung T. , Abdel-Fattah Amr I. 
Published: November 2017

Abstract
The application of conventional surfactant-based enhanced oil recovery (EOR) suffers from either the adsorption of the surfactant on the rock near the wellbore or from diffusion into small water-filled pores. An approach to mitigate the loss of surfactant and enhance deliverability to the oil phase is achieved by formulating the surfactant molecules into nano-sized particles, which are referred to as NanoSurfactant (NS) in this study. An essential step to unleash the potential of NS in EOR is the accurate understanding of its performance under conditions reasonably close to actual conditions.
In the current study, crude oil, synthetic brine, and petroleum sulfonate based NS were used. Eight limestone core plugs with a permeability range of about 125 millidarcies (mD) to 1282 mD were utilized in this study. Coreflooding was conducted under the near-reservoir condition. Advanced low-field nuclear magnetic resonance (NMR) techniques have been used to quantify the oil saturations by both secondary water injection and tertiary NS injection. The NMR techniques have also been used to assess the mechanisms underlying oil mobilization in carbonate core plugs. The protons in brine and NS solution were substituted with proton (H1) NMR invisible deuterium to enhance the contrast between oil and brine. The core samples were selected to investigate the effect of the NS soaking condition (soaking versus non-soaking), the NS injection rate, and the remaining oil saturation on the observed oil mobilization, respectively. All core plugs were initially saturated with oil and water, waterflooded, injected with NS (with and without soaking), followed by chase waterflooding. NMR measurements were conducted after each flooding stage.
The results of the current study demonstrate that the investigated NS has a great potential for EOR applications in carbonate reservoirs, and that soaking NS before chase waterflooding enhances its efficiency. Significant oil mobilization was observed when soaking was applied before chase waterflooding. The oil mobilization was much lower without soaking of NS for the cores with low quality and less oil wetting tendency. The analysis indicated that NS flooding can produce both of the trapped oil and oil adsorbed to the rock surfaces.
Extending Technology Limits – Application of Multistage Open Hole Horizontal Completion in Offshore Environment
Authors: Hall-Thompson Bryan , Ernesto Arias Urbina , Utaibi Abdullah A , Mashat Bahi , Vega Roberto 
Published: November 2017

Abstract
Multistage proppant and acid fracturing stimulation technology have contributed to increased hydrocarbon production in carbonate reservoirs. This technology has been deployed primarily in the Middle East’s onshore oil and gas fields for certain horizontal wells completed using Open Hole Multistage System (OHMS) with limited application in offshore environment.
OHMS was assessed for a low permeability carbonate reservoir offshore to evaluate well deliverability for a gas field and demonstrate its added value. Performing multistage stimulation in offshore environment is challenging and requires extensive planning and resources. This example looks at a 5-stage OHMS with single injection ports in +3,000 ft. segmented open-hole section to ensure efficient stimulation fluid placement. A High Rate Matrix Acid (HRMA) stimulation that creates highly permeable wormholes by pumping below fracture gradient is considered. These wormholes are conductive paths that improve near wellbore deliverability and avoid connectivity to any water in lower reservoir zones. The design considerations, field implementation of OHMS and HRMA are discussed. The technology is capable of increasing production performance by 2 folds of increase (FOI) relative to similar unstimulated cases.
This paper outlines the selection, execution, and challenges in deploying this technology. It discusses pretreatment formation evaluation, data requirement, data acquisition strategy, and key considerations for effective well completion and stimulation design. As an outcome, the paper highlights results and increased opportunities by applying this technology in offshore gas developments. It demonstrates value addition from rock property testing test, 1D Mechanical Earth Modelling (MEM), logging while drilling (LWD) well placement operations, and integration of wireline data, coring, imaging, sonic, and other data that ensure success.