bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automated Geometric Path Correction in Directional Drilling
Authors: Joshi Deep R. , Samuel Robello 
Published: October 2017

Abstract
For a drilling engineer, designing and following an optimum well path is of foremost importance to ensure efficient wellbore placement. But the departure from a planned path is quite common. The objective of this research was to define algorithms to detect a well going off from a planned path and to find the most efficient corrective path to enable downhole directional automation. The closed-loop algorithms were examined using a hardware simulator and a software simulator.
The path correction algorithms combine survey calculation methods like Minimum Curvature, Balanced Tangential and Natural Curve methods with complex curves like a cubic spline, Bezier, Catenary, and clothoid to describe the corrective path. Here, the corrective path is divided into two sections. The curve properties like curve length, curvature and torsion are determined based on the location of the nodal point between these sections which in turn defines the Well Profile Energy or WPE of the curve. In this work, the WPE was chosen as the efficiency parameter because it considers both bending and twisting of a curve while providing a quantitative value which signifies efficiency of a curve. Combining a curve with a survey calculation method yields a unique well path corresponding to the minimum WPE for that combination and the most efficient corrective path will be chosen by comparing WPE for all twelve possible combinations of curves and survey methods.
To test the applicability of the path correction algorithms in a continuous downhole system, a MATLAB-based software simulator was designed. The dynamic deviation of the well due to factors like bit walk, formation heterogeneity, local stress regimes, bit walk and error in the directional drilling tools was applied using an arbitrary ‘Deviation Factor’. With its inclusion, we could simulate dynamic downhole drilling conditions in the simulator. Several parameters like maximum allowable curvature, torsion, maximum allowable inclination, allowable length of the corrective path were used to ensure a realistic, drillable path. Real-time application of the closed-loop algorithms was successfully examined by designing a hardware prototype controlled by a microcontroller. The directional changes were applied using two linear actuators and the resulting directional survey was recorded using a three-axis accelerometer.
This study provides three-dimensional algorithms for detecting when a well goes off path and finds the most efficient corrective path. The corrective path replaces the planned path and is continuously tracked for accuracy, making this a continuously closed loop system that, if combined with a MWD system, can enable an automated downhole directional drilling system.
A Comprehensive Model for Investigation of CO2-EOR with Nanopore Confinement in the Bakken Tight Oil Reservoir
Authors: Zhang Yuan , Di Yuan , Yu Wei , Sepehrnoori Kamy 
Published: October 2017

Abstract
CO2 injection is an effective enhanced oil recovery (EOR) method in unconventional oil reservoirs. However, the investigation of CO2 Huff-n-Puff in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider the nanopore confinement in both phase equilibrium and fluid transport. Hence, we develop an efficient model to fill this gap and apply it in the field production of the Bakken tight oil reservoir. Complex fracture geometries are also handled in this model.
First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterwards, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2-EOR in the Bakken tight oil reservoir. Based on the prediction of the field data, the MMP is 5.4% lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the impacts of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 Huff-n-Puff process. Results show that both CO2 diffusion and capillary pressure effect improve oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken formation with the non-planar fractures and natural fractures. Contributions of CO2 diffusion and capillary pressure effect are also examined in depth in field scale with the complex fracture geometries. The oil recovery factor of CO2 Huff-n-Puff process with both CO2 diffusion and capillary pressure effect increases by as much as5.1% in the 20-year period compared to the case without these factors.
This work efficiently analyzes the CO2 Huff-n-Puff with complex fracture geometries considering the CO2 diffusion and nanopore confinement in the field production from Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex fracture geometries in the tight oil reservoirs.
Successful Application of Well Testing and Electrical Resistance Tomography to Determine Production Contribution of Individual Fracture and Water-Breakthrough Locations of Multifractured Horizontal Well in Changqing Oil Field, China
Authors: He Youwei , Cheng Shiqing , Qin Jiazheng , Chen Jianwen , Wang Yang , Feng Naichao , Yu Haiyang 
Published: October 2017

Abstract
It is observed that production rates decline quickly and water-cut rises to 90% only after two or three years’ production for many multifractured horizontal wells (MFHWs) in China. Reliable measurements are critical to assess production performance and diagnose water-breakthrough positions to arrange the subsequent operations (e.g. stimulation and water plugging). Although production-logging test (PLT) is an effective method for production performance evaluation, the MFHW might be scrapped during the test and PLT is also expensive for an MFHW. To solve this problem, this paper proposes an approach to determine the production contribution of individual fracture and locate water-breakthrough segments along horizontal wellbore by combination of well testing and electrical resistance tomography (ERT).
Firstly, a well testing model is developed to model pressure behavior of an MFHW intercepted by asymmetric fractures with arbitrary locations, unequal conductivity and production. Secondly, model validation demonstrates the accuracy of the well testing model proposed in this paper. Thirdly, sensitivity analysis shows that early-radial flow becomes remarkable as spacing between producing fractures or numbers of producing fractures decrease. N* is defined to characterize the number of mainly producing hydraulic fractures (NMPHF), and the value of N* depends on fracture properties (e.g. half-length, spacing, conductivity) besides the NMPHF. Fourthly, the well testing model is applied to estimate the flow profile through history matching of bottomhole-pressure (BHP) data. Fifthly, the introduction of ERT method solves the difficult to distinguish oil and water profile compared with well testing method, enables us to monitor the water-breakthrough locations and reduces the multiplicity of well testing interpretation in well performance evaluation.
Finally, this method has been successfully applied to Changqing Oil Field, and results obtained by well testing and ERT method coincide with PLT, which enable petroleum engineers to carry out stimulation strategies to improve production performance and decrease the water-cut of MFHWs.
Customizing Polymer Rheology for Application in Commercial Scale Polymer Floods
Authors: Fortenberry R. , Hernandez R. , Li Z. , Delshad M. 
Published: October 2017

Abstract
Reservoirs facing challenges such as high oil viscosity and high heterogeneity benefit from polymer flooding by decreasing unfavorable mobility ratios or improving crossflow. Despite this diversity of needs, polymer floods are often designed around a single point viscosity value, which doesn't account for variable shear rates in the porous media, in-situ viscosity, challenges with fluid injectivity, etc.
Polymers have diverse rheological characteristics. For example, synthetic polymers like HPAM are elastic and can range in their degree of shear sensitivity, while biopolymers like scleroglucan are inelastic and highly shear-thinning. We generated laboratory data for two such polymers, scleroglucan and an Acrylamide-ATBS Co-Polymer. We developed parameters to describe their rheological characteristics for a variety of models, including shear thinning, shear thickening and preshearing.
We then assessed the impact of these attributes on polymer flooding performance using UTCHEM, the University of Texas Chemical Flooding Reservoir Simulator. Polymer injectivity, viscosity, and shear rate were assessed for sensitivity to polymer rheology using simplified models of radial geometry. These results were correlated to laboratory experiments to ensure correct estimate of in-situ viscosities. Sensitivity to a variety of important parameters, including shear rate correction factor, simulation grid size, shear-thickening, and skin were also completed. A final sensitivity study was conducted using a heterogeneous reservoir model with the multiple patterns.
Simulations using the simplified radial model and the heterogeneous, commercial scale model support the same conclusion: the specifics of polymer rheology can have a significant impact on polymer flooding performance, and polymer rheology should be considered an important design attribute along with injection viscosity and retention. We show that injection of an elastic, HPAM-based polymer may require higher injection pressure or lower rates than a highly shear-thinning, inelastic biopolymer like scleroglucan. We also demonstrate how the differences in rheology impact reservoir pressure, in-situ viscosity distribution, in situ shear-rate distribution and flow into various reservoir layers.
Modern Completion Optimization in the Haynesville Shale
Authors: Cadotte R. J. , Whitsett Andrew , Sorrell Melfard , Hunter Ben 
Published: October 2017

Abstract
Haynesville Shale gas production (per day) decreased by half between late 2011 and mid-2016. This resulted from a combination of factors, including steeper declines in production per well than in other unconventional plays and reduced activity related to economic conditions. In 2016, however, drilling activity increased in the Haynesville Shale play as economic conditions improved because of higher natural gas commodity prices and new completion techniques were employed resulting in larger stimulated reservoir volume and more fracture initiation points along the wellbore.
Haynesville completions have continued to progress toward optimization, despite experiencing a lull in activity. Completion design parameters that have been altered to optimize production include lateral length, proppant volumes, proppant size, proppant type, and base fluid chemistry. Further, new technologies, such as intrastage degradable diverters and dissolvable plugs, have also been used to help increase production and improve asset utilization.
A comprehensive study was conducted comparing completion techniques used during original completions of early Haynesville Shale development to those deployed during the past year. The increase in normalized proppant volumes used per well is one of the most significant changes documented. By evaluating an acreage positon that was originally completed by multiple operators over a multiyear timeframe, an in-depth investigation of the impact of proppant volume on production in similar acreage can be completed. The effect of other completion parameters can also be evaluated.
After-Closure Idiosyncrasies of Fracture Calibration Test Analysis in Shale Formations
Authors: Marongiu-Porcu Matteo , Retnanto Albertus 
Published: October 2017

Abstract
Fracture Calibration Tests (FCT), are strategically used to estimate, amongst other important parameters, reservoir permeability and pore pressure during early appraisal stages of unconventional formations, where estimation of permeability and pore pressure by pressure transient buildup tests is impossible because no flow occurs without hydraulic fracture stimulation. This study investigates some of the idiosyncrasies that have been reported in a large number of FCTs, which make after-closure (AC) analysis ambiguous or inconsistent.
We recently introduced a novel comprehensive model for FCT analysis, combining before-closure (BC) and AC behavior in a fully consistent way, facilitating the detection of abnormal BC events (i.e. multiple closure and non-linear leakoff) and improving the intrinsic weakness of standalone AC analysis methods. Extensive use of this model on a vast number of shale gas FCTs has revealed the existence of apparent AC anomalies. This paper provides a novel approach to identify and diagnose these apparent anomalies and reconcile them with unique aspects of the tested unconventional shale formations.
In the AC anomaly that we firstly addressed in SPE-144028-MS, the logarithmic derivative shows only a minimal indication of formation linear flow, showing instead an abrupt transition to pseudo-radial flow. This unresolved anomaly inspired the work presented in this paper, where twenty FCT published case histories were used to study and reveal four distinct anomalies: –AC logarithmic derivative exhibits unit slope, a symptom of horizontal fracture;–Multiple closures followed by AC logarithmic derivative that exhibits a late-time "hook";–AC logarithmic derivative exhibits abrupt transition to pseudo-radial flow with limited or no linear flow;–AC logarithmic derivative exhibits an apparent dual porosity "dip".
These AC idiosyncrasies have been rationalized and integrated into our established comprehensive model for FCT analysis, allowing a realistic characterization of the geological, tectonic, and wellbore -related geometric signatures that very commonly manifest themselves in all shale formations.
Numerical Modeling of Proppant Transport in Complex Hydraulic Fracture Propagation
Authors: Izadi Ghazal , Hoeink Tobias , Cruz Leonardo , Copeland Dylan 
Published: October 2017

Abstract
Hydraulic fracturing is a stimulation technique used in unconventional reservoirs to generate sufficient reservoir contact for viable production. During stimulation, proppant is pumped into the system to keep fractures open when, at a later stage, injection ceases and fluid is recovered as fractures close. Thus, controlling proppant distribution in the fracture is important to improve well productivity. Several factors influence proppant placement and settling such as proppant size, proppant density and carrier-fluid rheology. However, accurately predicting, and consequently optimizing, proppant placement in complex fracture systems remains an industry challenge. The objective of this study is to use advanced modeling techniques of proppant transport inside complex fracture systems using a 3D simulator that couples geomechan ics, fracture mechanics, fluid behavior and proppant transport to assess the optimization of stimulation treatments. In this study proppant transport models incorporate the interaction between hydraulic fractures (HF) and natural fractures (NF) of various sizes and orientations. Treatments were simulated in systematic variations of proppant size, proppant density and fluid viscosity. Fluid rheology, proppant size and density are all major parameters affecting the proppant settling rate. In more complex systems, proppant placement is strongly influenced by the location, size, and orientation of natural fractures. Based on the size of proppant and viscosity of the injected fluid, proppant may or may not enter the natural fractures.
Maximizing CO2 Accumulation in Storage Reservoirs: Interplay between Permeability Retardation and Capillary Trapping of Rising CO2
Authors: Ren Bo , Delaney Jennifer M. , Lake Larry W. , Bryant Steven L. 
Published: October 2017

Summary
The main objective of this work is to understand, by analytical and numerical study, how permeability retardation interacts with capillary barrier trapping to cause accumulation as CO2 migrates upward in saline aquifers during geological sequestration.
The study is of one-dimensional two-phase (CO2 and water) countercurrent flow. The analytical model describes CO2 buoyant migration and accumulation at a "flow barrier zone" (low permeability) above a "flow path zone" (high permeability). The relative importance of permeability retardation and capillary trapping is examined under different magnitudes of buoyant source fluxes and porous media properties. In the limiting case of zero capillary pressure, the model equation is solved using the method of characteristics. Permeability-retarded accumulation, induced by the permeability difference between the flow path and the barrier zone, is illustrated through CO2 saturation profiles and time-distance diagrams. Capillary trapping is subsequently accounted for by graphically incorporating a capillary pressure curve and capillary threshold effect.
Results demonstrate that the accumulation contributions from both the permeability hindrance and capillary trapping are convolved at sufficiently large fluxes. At a given time, the total CO2 accumulated is greater than for capillary trapping, but the former approaches the latter at large time. The low permeability zone need not be completely impermeable for accumulation to occur. We demonstrate that considering only capillary trapping understates the amount of CO2 accumulated beneath low permeability structures during significant periods of a sequestration operation.
A New Three-Phase Microemulsion Relative Permeability Model for Chemical Flooding Reservoir Simulators
Authors: Lashgari Hamid R. , Pope Gary A. , Tagavifar Mohsen , Luo Haishan , Sepehrnoori Kamy , Li Zhitao , Delshad Mojdeh 
Published: October 2017

Abstract
This paper presents a new three-phase relative permeability model for use in chemical flooding simulators. Numerical simulation test cases are presented to illustrate the continuity of the new relative permeability model. Comparisons are made with a three-phase relative permeability model that has been widely used in chemical flooding simulators for decades. These comparisons show the old model has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters and requires less experimental data to determine the relative permeability parameters compared to the original model. Simulations using the new model showed excellent agreement with ASP coreflood data.
Deployment of a Self-Adjusting Bit to Solve Todays Drilling Vibration Challenges and Optimize Performance
Authors: Phillips Anthony , Stefanik Thomas M. 
Published: October 2017

Abstract
For well over a decade, we have been using depth-of-cut (DOC) control to control the aggressiveness of polycrystalline diamond compact (PDC) bits. In recent years, the ability to change the aggressiveness has been an effective way of mitigating vibrations, in particular for stick-slip. The amount of fixed DOC control is determined for a particular formation or DOC, but it can limit performance in other parts of the well, or not solve vibration problems in multiple formations. This paper demonstrates that having a PDC bit with innovative self-adjusting DOC control can mitigate these vibrations to enable improved performance through each section of the well.
In the selected application in South Texas, torsional vibrations or stick-slip can be problematic, damaging the bit or downhole tools and reducing drilling performance. Performance metrics and dull conditions were collected to prove the presence of torsional dysfunction. Current bit styles have acceptable performance; however, the bit life has limitations regarding vibrations. Mitigating vibration is required to improve the performance of the bit and system. The addition of the self-adjusting DOC control feature changes the bit aggressiveness continually during the drilling operation, helping to achieve optimal performance.
When the self-adjusting feature engages with rock for steady state drilling, the feature gradually retracts, controlling the DOC to find the optimal exposure of the element for the current drilling parameters and formations. As dynamic instabilities occur, the self-adjusting feature reacts at fast time scales to mitigate the event. Comparing this technology to the offsets, the drilling data at surface show improved performance with 196% distance drilled while the downhole data show there is a smooth drilling response throughout the run.
A bit with the innovative self-adjusting DOC control can adapt to the downhole variables, prolonging its life and helping operators achieve their goals more efficiently, or with minimal driller intervention. Previously validating the concept in research wells it is now demonstrated in field trials with a reduction in torsional vibrations.
A New NMR-Based Method for Wettability Assessment in Mixed-Wet Rocks
Authors: Tandon S. , Rostami A. , Heidari Z. 
Published: October 2017

Abstract
Nuclear Magnetic Resonance (NMR) measurements can be used for quantifying rock wettability because they are sensitive to the type of fluids in contact with grains. Conventional experimental NMR-based methods for wettability determination often need NMR response for the same rock sample in different wettability states at irreducible water saturation and at residual oil saturation, which is time-consuming and could provide non-unique results. There also exist simulation-based methods for characterizing wettability in mixed-wet rocks. These methods either assume oversimplified pore shapes or require microComputed Tomography (CT) images of partially-saturated mixed-wet rock samples and complex image processing algorithms, which makes them computationally expensive. In this paper we introduce a new NMR-based wettability index for characterizing rock wettability and test its applicability in both carbonate and sandstone rock samples using numerical simulations.
The new NMR-based wettability index is a function of measured transverse magnetization (72) of mixed-wet rock, bulk relaxation and saturation of each phase, and simulated T2 distributions for fully water-saturated and fully hydrocarbon-saturated. We then use pore-scale simulation of NMR at different wettability states to verify the applicability and reliability of the newly introduced wettability index in rock samples with different pore structures including carbonate and sandstone samples. The first step in model verification is to obtain pore-scale images of few rock samples in each rock type in the formation. We then perform simulation of NMR T2 response for rocks with different wettability levels by numerically solving Bloch-Torrey equation using finite volume method. Then we generate mixed-wet synthetic samples, simulate the T2 response in the synthetic samples, and use the simulation results as inputs for determining their NMR-based wettability index.
The results demonstrate the reliability of the new NMR-derived wettability index. The introduced NMR-based method for wettability assessment allows for determination of wettability at any saturation state in the rock samples. It also eliminates the need for NMR calibration at irreducible water saturation and residual oil saturation and thus, might reduce the overall time required for determining wettability of mixed-wet samples. Successful application of the introduced workflow expedites assessment of wettability index and wettability changes in mixed-wet reservoir rocks.