bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methods to Maximize Completion Efficiency in the Eagle Ford Reservoir
Authors: Smith Charles H , Bashkirtseva Alena 
Published: April 2015

Abstract
Unconventional reservoirs depend on an effective system of completion to achieve good production. The rock is less rigid than conventional formations and, in some circumstances, will display a plastic nature. Portions of the rock could demonstrate a flow capacity that could complicate flow paths created by fracture stimulation. The Eagle Ford exhibits some of these potentially troublesome characteristics.
Dipole sonic logs have been used to establish Young's modulus and Poisson's ratio for the frac design. These same measurements are useful in unconventional reservoirs, but more complex data are necessary. Traditional two-dimensional (2-D) models of these values do not necessarily maintain their relationship in the horizontal portions of the well. The determination of vertical and horizontal components of Young's modulus and Poisson's ratio from the dipole sonic can be incorporated into the treatment design.
The ability of the reservoir fluids to migrate through the fractures created by the treatment also requires some additional attention. If the fluids will not release into the created fractures, this portion of the reservoir will be unproductive. Just as in traditional reservoirs, permeability must be defined as an important reservoir parameter. Permeability established by nuclear magnetic resonance (NMR) determines the most efficient treatment area of the reservoir. These considered together help provide the best potential completion in unconventional reservoirs, including the Eagle Ford.
This paper includes examples of the NMR determination of apparent permeability, along with examples of dipole-sonic vertical and horizontal calculations from the Eagle Ford. These calculations are used to determine the best landing horizon for the horizontal well and the best completion sections in the horizontal wellbore.
New Rotary Steerable Drilling System Delivers Extensive Formation Evaluation for High Build Rate Wells
Authors: Biscaro Enrico , D'Alessandro John David , Moreno Adriana , Hahn Matthias , Lamborn Raymond , Al-Naabi Mohammed H. , Bowser Aaron C. 
Published: April 2015

Abstract
A new high build-up rate (HBR) rotary-steerable drilling system (RSS) with comprehensive logging-while-drilling (LWD) capabilities was developed and commercialized. The new HBR RSS was designed to provide extensive LWD services, including propagation and deep resistivity, neutron and density porosity measurements, borehole imaging and many others at build-up rates up to 12°/100 ft. Using closed-loop control and a short steering sleeve that decouples steering functionality from drilling dynamics, the system can perform open-hole sidetracks and drill high dogleg severity (DLS) curves and laterals in one run with precise directional control and well placement, without exceeding the fatigue limits of the LWD tools.
In many areas around the world, rotary-steerable systems have replaced steerable motors because of the inherent advantages of RSS technology [1], including improved directional control, reduced wellbore tortuosity [2] and comprehensive logging-while-drilling (LWD) measurements. However, some applications require drilling and evaluating wellbores with higher build-up rates (BUR) than possible with a standard RSS. Developments in drilling tool design have increased the achievable BUR of rotary steerable systems to values on par with those of steerable motors. This achievement introduces a challenge related to the bending loads of the sophisticated LWD tools positioned behind the HBR RSS. When run with a steerable motor, the high bending loads on the LWD tools are primarily in static, because the curvature is created in a sliding mode of the drillstring. When run with a HBR RSS, the LWD tools are exposed to high cyclic bending loads because the string is constantly rotating. As a result of this challenge, the selection of LWD measurements available in HBR RSS applications is very limited.
The authors present the design, simulation criteria and commercial results of the new HBR RSS in several operating environments, including the Western region of the USA and the Middle East. Drilling high DLS curves increased the length of laterals by several hundred feet, enabling additional reservoir exposure and ultimate recovery. The system drilled entire sections in one run and improved operational efficiency by the elimination of sliding. If formation tops arrived unexpectedly, or faults were encountered during geo-steering, the new HBR RSS system reduced the out of zone depth interval, thereby increasing recoverable reserves. The innovative HBR RSS system is used in many applications around the world to drill and evaluate complex wells with high DLS, as well as straight laterals, with precision and efficiency.
Lessons learned during the commercial application of this functionality and technologies are presented with the industry to ensure the maximum value is achieved in the shortest amount of time possible.
Modeling and Simulation of WAG Injection Processes - The Role of Counter-Current Flow
Authors: Sherafati Marjan , Jessen Krisitan 
Published: April 2015

Abstract
In this work, we investigate the effect of flow reversals from co-current to counter-current flow on the displacement performance of Water Alternating Gas (WAG) injection processes. In WAG processes, gas migrates towards the top of the formation while water tends to move towards the bottom of the formation. The segregation of gas, oil and water phases will result in counter-current flow occurring in the vertical direction in the reservoir. Previous experimental and theoretical studies of counter-current flow have shown that the relative mobility of each of the phases in the system is considerably less when counter-current flow prevails as compared to co-current flow settings. A reduction of relative permeability in the vertical direction results in a dynamic anisotropy in relative mobility. This effect has, to the best of our knowledge, not previously been considered in the simulation of WAG processes.
A new flow model that accounts for flow reversals in the vertical direction has been introduced into a three-phase compositional IMPEC simulator. In order to investigate the impact of flow reversals, results from the new flow model are compared to cases where counter-current flow effects are ignored. A range of displacement settings, covering relevant gravity numbers and miscibility conditions (near-miscible and multi-contact miscible), have been investigated to gauge the impact of mobility reductions due to flow reversals. Simulations with different slug sizes are also included in this study. Significant differences, in terms of saturation distribution and oil recoveries, are observed between the conventional flow model (ignoring mobility reductions due to counter-current flow) and the proposed new model accounting for counter-current flow effects on phase mibilty in the vertical direction. Accordingly, we recommend that an explicit representation of flow transitions between co-current and counter-current flow (and the related impact on phase mobilities) should be considered to ensure accurate and optimal design of Water Alternating Gas injection processes.
Stability Analysis of Multilateral High Density Pad Wells in the Three Forks Formation
Authors: Ostadhassan M. , Zamiran S. , Jabbari H. , Osouli A. , Bubach B. , Oster B. 
Published: April 2015

Abstract
In order to increase the productivity from the Three Forks Formation, drilling horizontal well and multilateral ones, in particular, seems inevitable. A multilateral well is defined as a single well with one or more wellbore branches radiating from a main vertical borehole. A successful multilateral well that replaces several vertical wellbores will not only increase production, but also reduces overall drilling and completion costs, and allows more efficient hydraulic fracturing operations. Reducing surface impoacts while developing a field is a major benefit of this drilling plan. Well placement and design to have enough stability where in-situ stresses are disturbed dramatically due to short well spacing and stress shadowing is a crucial task, which should be studied prior to any drilling operation. Instability problems in multilateral wells can result from stress interplay among nearby wellbores.
In this paper, instability of the borehole around the horizontal section of the high-density multilaterals, also known as pad drilling is studied. This drilling technique is growing very fast in the Williston Basin to increase production from two main hydrocarbon layers in the basin, Bakken and Three Forks Formations. Focusing on the Three Forks Formation, mechanical properties of this rock unit such as Poisson's ratio, Young's modulus and Unconfined Compressive Strength (UCS) have been extensively investigated and reported through filed data and lab experiments. These parameters, along with the calculated in-situ principal horizontal and vertical stresses, were input into a numerical simulation software, Flac 2D, to understand drilling impacts and to analyze borehole instability through a geomechanical model. For the final results, we have presented stress perturbation, rock displacements and creation of different failure zones around the borehole in the vertical and horizontal direction after the medium is penetrated.
Low-Salinity Brine Enhances Oil Production in Liquids-Rich Shale Formations
Authors: Nguyen Christina , Kothamasu Ramya , He Kai , Xu Liang 
Published: April 2015

Abstract
Low-salinity waterflooding has proven to be an appealing technique for enhancing oil recovery in conventional reservoirs. However, few studies have been conducted on low-salinity brines (LSBs) for hydraulic fracturing in liquids-rich shale plays with or without surfactant. Additionally, as operators tend to shift from fresh water to 100% produced water, the implications of such a switch must be understood from a production standpoint. Therefore, the effects of LSBs on oil recovery from liquids-rich shale should be investigated.
In this study, LSBs with or without surfactant were injected into the crushed, oil saturated Muskwa shale from Canada. Laboratory results suggest that LSB (≤4% KCl) extracts more hydrocarbon than high salinity brine (HSB) (≥8% KCl). Notably, additional oil recovery was observed when surfactant was used in LSB. Interfacial tension (IFT) reduction decreased with increasing salinity but remained constant for LSB with surfactants across all salinities examined. Short-lived oil in water emulsions were observed in LSB in the presence of surfactant. Additionally, LSBs with surfactant were injected into a microfluidic based reservoir on a chip (ROC) device, where pore size was comparable to that of shale. The visualized oil recovery on the ROC was consistent with that found in core flooding tests.
These reported results provide a potential methodology for optimizing source water before hydraulic fracturing operations. LSBs with properly tailored surfactant additives are imperative to helping enhance well productivity.
Conductivity of Proppant-Packs under Variable Stress Conditions: An Integrated 3D Discrete Element and Lattice Boltzman Method Approach
Authors: Mollanouri Shamsi M.M. M , Farhadi Nia Sh. , Jessen K. 
Published: April 2015

Abstract
The conductivity of the proppant-pack plays a critical role in the productivity of a hydraulically fractured well. Here we combine the Discrete Element Method (DEM) and the Lattice Boltzmann Model (LBM) to investigate the conductivity of proppant-packs under variable confining stress. Three different proppant-packs including well graded, uniformly graded and poorly graded proppants are used to generate loose packing of spherical rigid particles with no initial contact. We then use a DEM algorithm, with specified confining stress, to compact the proppant-packs. A representative elementary volume of the pack is subsequently used for fluid flow simulations. LBM is used to calculate a detailed flow field at the pore scale and the Darcy-scale permeability is then calculated from the average pore-scale velocity and pressure information. The results show, as expected, that the porosity and permeability of the proppant-pack decreases with increasing confining pressure. The permeability of well graded proppant-packs is more sensitive to the stress while uniformly graded packs are more permeable than poorly graded proppant-packs. The calculated permabilities are in good agreement with available experimental data for a range of confining pressures. In addition, the permeability estimated from the Kozeny-Carman equation based on calculated porosities compares well with calculated permeabilities.
Shale Asset Production Evaluation by Using Pattern Recognition
Authors: Esmaili S. , Mohaghegh S. D. , Kalantari-Dahaghi A. 
Published: April 2015

Abstract
Shale gas as one of the most important source of energy in US requires long-term development plans and reservoir management. Better understanding of the inherent complexities of shale system and identifying the key contributing parameters are essential for optimum operation of such assets. Different assessment techniques such analytical, numerical and statistical analyses have been applied to large multi-variable data set from shale assets with different degrees of success.
In this paper, advanced Data-Driven Analytics that incorporates pattern recognition capabilities of Artificial Intelligence, Machine Learning and Data Mining is used to understand and rank the contribution and influence of rock characteristics and design parameters during the production from shale. Advanced Data-Driven Analytics provides much needed insight into hydraulic fracturing practices in Shale. Unlike analytical and numerical techniques that are based on “Soft Data,” Advanced Data-Driven Analytics incorporates “Hard Data”. “Hard Data” refers to field measurements (facts) such as drilling information, well logs (Gamma ray, density, sonic, etc.), hydraulic fracturing fluid type and amount, proppant type, amount and concentration, ISIP, breakdown and closure pressures, and rates, while “Soft Data” refers to variables that are interpreted, estimated or guessed (and never measured), such as hydraulic fracture half length, height, width and conductivity or the extent of the Stimulated Reservoir Volume (SRV).
In this study, a spatio-temporal database including well locations and trajectories, reservoir characteristics, completion, hydraulic fracturing, and production parameters for a large number of horizontal wells in Marcellus Shale is generated. The impact of parameters such as up-dip versus down dip deviation of wells, TOC, porosity, stimulated lateral length and cluster spacing, etc. on production from wells in a shale asset is analyzed and the understandable trends and patterns in the database are identified. The analyses are performed using production from multiple time intervals (i.e. different production indicators) throughout the life of wells.
Spontaneous Imbibition Study: Effect of Connate Water Composition on Low-Salinity Waterflooding in Sandstone Reservoirs
Authors: Shehata Ahmed M. , Nasr El-Din Hisham A. 
Published: April 2015

Abstract
Extensive experimental work has indicated that low-salinity waterflooding is an enhanced oil recovery technique that improves oil recovery by lowering and optimizing the salinity of the injected water. Most of the low-salinity waterflooding studies focused on the injection brine salinity and composition. The question remains, how does the salinity and composition of the reservoir connate water affect the low-salinity waterflooding performance? Therefore, in this work different connate water compositions were used to investigate the role of reservoir connate water on the performance of low-salinity waterflooding.
In this paper, nine spontaneous imbibitions experiments were performed. Two sandstone types (Bandera and Buff Berea) with different clay contents were used. The mineralogy of the rock samples was assessed by X-ray powder diffraction, scanning electron microscopy, and X-ray fluorescence. This work describes the experimental studies of the spontaneous imbibition of oil by low-salinity and high-salinity brines using 20 in. length outcrop samples. The main objectives of the spontaneous imbibition study was to investigate the role of the composition of the reservoir connate water (Na+, Ca2+, and Mg2+), the effect of rock permeability, and test the effect of temperature (77 and 150°F) on the performance of the low-salinity waterflooding recovery. The volume of the produced oil was monitored and recorded against time on a daily basis. Imbibition brine samples were analyzed at the end of each experiment.
Results demonstrate that the spontaneous imbibition oil recovery ranged from 38 to 69% OOIP for high permeability Buff Berea cores (164-207.7 md), while oil recovery of the low permeability Bandera cores (31.1-39.2 md) ranged from 20 to 51.5% OOIP at 77°F and 14.7 psia. The oil recovery decreased when the average pore-throat radius decreased. The reservoir connate water composition has a dominant influence on the oil recovery rate. The changes in the ion composition of reservoir connate water (Ca2+, Mg2+, and Na+) showed a measurable change in the oil production trend. Reservoir cores saturated with connate water containing divalent cations of Ca+2 and Mg+2 showed higher oil recovery than for cores saturated with monovalent cations Na+. In all cases, a measurable ion exchange was observed, while there was no significant change in the pH of the imbibition brine during the experiment. The ions exchange effect was more pronounced than the pH effect in the low-salinity waterflooding performance for Buff Berea and Bandera sandstone. As the temperature increased from 77 to 150°F, an additional oil recovery up to 15.4% of OOIP was observed by spontaneous imbibition for Buff Berea cores.
Capillary Pressure Measurement using Reservoir Fluids in a Middle Bakken Core
Authors: Karimi S. , Kazemi H. 
Published: April 2015

Abstract
In the United States, the organic-rich shale resource has become a great source of high-quality light oil to meet the domestic energy demand. For reservoir evaluation and enhanced oil recovery planning, knowing shale wettability characteristics is critical. To address these issues, we measured a series of capillary pressures in a shale sample using formation fluids. Specifically we measured drainage, imbibition, and forced imbibition capillary pressures to quantify wettability, and the mobile fluid saturation window in the shale matrix.
In this study, we report on the use of a centrifuge to generate a complete envelope of drainage and imbibition capillary pressure data for a Middle Bakken core plug. In addition to capillary pressure measurement, we measured the irreducible water and oil saturation, and fluid production versus time during different centrifuge cycles. We used the latter measurements and data to calculate relative permeability for oil and water.
The experiments were very time consuming because of the low core permeability; however, carefully designed centrifuge experiments are valuable for reservoir engineering evaluations and reservoir simulation studies. Contrary to a common perception, mercury intrusion capillary pressure measurements cannot be converted to usable oil-water or gas-liquid capillary pressure data for use in reservoir studies (thus, not a good substitute for direct measurements with reservoir fluids). The mercury intrusion data is only useful for pore-size distribution calculations.
Because of the small pore throats and low permeability of shale reservoirs, capillary pressures affect both the primary and enhanced oil recovery in shale reservoirs. For instance, forced imbibition cycle is very steep, and the mobile oil saturation window is very narrow. Thus, based on our measurements, we conclude that water flooding oil recovery in Middle Bakken formation is unlikely to succeed. On the other hand, centrifuge gas displacement in core plugs showed a greater promise for oil recovery success.
The Development of Artificial-neural-network-based Universal Proxies to Study Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) Processes
Authors: Sun Qian , Ertekin Turgay 
Published: April 2015

Abstract
Steam injection is one of the most broadly deployed enhanced oil recovery techniques in heavy oil reservoirs. Numerical reservoir simulation plays a significant role in studying the mechanism and design of the field development strategies of steam injection procedures. Artificial neural network (ANN) is considered as a powerful subsidiary tool for high fidelity numerical models for its fast computational speed, especially when large volume of simulation runs are required (Monte Carlo simulation, sensitivity analysis and population-based optimization). This paper focuses on the discussion of the development of ANN-based proxy models studying steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) procedures. The proxy models will consider rock and fluid properties such as relative permeability and temperature dependent fluid viscosity as variables so that they will be capable of handling different types of reservoirs and formation fluids. Half of the SAGD well pair is selected as the minimum unit to study. The ANN model will predict the oil flow rate and cumulative oil production profiles of a SAGD project. To better utilize the injected heat, the CSS procedure in this paper is designed in such a way that the cycle will automatically switch when the oil flow rate in the production phase drops down to a certain threshold value. The project will be terminated when the initial flow rate of one cycle could not maintain the threshold oil flow rate. Following this design scheme, the total number of cycles within the production life will be an unknown. Given a certain set of input parameters, the proxy model will predict the number of CSS cycles and the corresponding oil flow rate and cumulative production profiles. The CSS proxy model developed in this work could be implemented in studying both conventional oil sands and naturally fractured reservoirs. Furthermore, the proxy models developed in this work could be implemented as screening tools which provide engineers with an opportunity to obtain fast recovery estimation of SAGD and CSS projects. They may also assist high fidelity model in history matching, or be employed as proxies in sensitivity analysis and population-based optimization. The ANN proxy models discussed in this paper are parts of a comprehensive ANN-based screening toolbox which is an ensemble extensive EOR processes.