bluuebunny/crossref_metadata_2025_split huggingface dataset:
OCTG Advancements in Casing Drilling: Where We Have Been and Where Are We Going?
Authors: Grijalva O. , Holzmann J. , Oppelt J. , Perozo N. , Paz C. , Asgharzadeh A. 
Published: March 2017

Abstract
The technique of drilling a well using the casing string has earned itself a well deserved place as one of the most effective and cost-saving ways to drill and complete a hydrocarbon well; the cornerstone of this is the casing pipe, composed by the pipe body itself and the threaded connection. Normally an API-Buttress type connector is used; nevertheless, it has been proven in both controlled and field conditions that this connector is not completely adequate for Casing Drilling per se, as high torque capacities are demanded. Apart from that, and due to this condition, the constant need for using torque enhancers represents a high limitation to the Drilling with Casing technique itself. For this, Premium-type connectors address this point in a more proper way in form of improved geometries in thread and shoulder profiles and enhanced sealing capabilities.
Despite of this, Premium Connections are seldom used in Casing Drilling applications, being them almost relegated to very special, seldom drilling deployments. However, successful use of Premium Connections in Casing Drilling projects offshore Australia, Norway and onshore Mexico are paving the road for an intensive inclusion of Premium Connections in the field; this has also come as the result of the current diversification of the OCTG market for this connectors coming after a better understanding of load distribution and torque "control" by means of improved geometric design combined with the successful integration of axial-symmetric modeling (Finite Element Method) and Full Scale Testing for design and validation of new couplings. In this work, a holistic approach will address the technological highlights making up the past and current market offer and future tendencies in OCTG specialty connectors for casing drilling, understanding this as the direct result of the evolution of this drilling technique and the recent improvements in Full Scale Testing and computer-assisted design.
It was observed that the drilling of horizontal sections with a casing string in some field developments worldwide was only possible between 1990-2010 due to important modifications made to Full Scale Testing procedures employed to validate newly designed Premium Connections. In this case, the inclusion of a testing stage with bending broadened the usage spectrum in which some Premium Connection geometries were able to perform well; this serves as a concise, yet significative example of the constant evolution the OCTG sector underwent in the last decades, and also a great example of the superb applicability of Premium Connections in high demanding oilfield operations like drilling a well with casing pipe.
This work brings new light into the understanding of the potential of Premium Connections as a standard selection parameter for OCTG used in Casing Drilling, understanding the combined usage both technologies as a clear warrant towards well integrity.
Lateral Wellbore Rock Characterization and Hydraulic Fracture Optimization Utilizing Drilling Cuttings and Mud Log in Cleveland Sand: A Case Study
Authors: Stolyarov Sergey , Gadzhimirzaev David , Sadykhov Said , Ackley Benjamin , Lipp Casey 
Published: March 2017

Abstract
Optimizing a hydraulic fracture stimulation in a horizontal well requires an understanding of the petrophysical properties, and the near-wellbore and far-field stresses along the entire lateral. Such reservoir characterization is normally developed from a geomechanical and petrophysical analysis using wireline or logging-while-drilling services that include acoustic and borehole-image logs. Unfortunately, economic considerations often inhibit or preclude complete characterization, especially in the current economic climate.
An affordable and convenient alternative for reservoir characterization is to use commonly recorded data, such as drilling mechanics and steering information, to provide a gross characterization. Adding a comprehensive drill cuttings analysis provides insight into rock texture, mineralogy, and rock properties along the entire length of the lateral that is not available from the nominal real-time services. When performed in real time, such studies help ensure that the well stays on-target and within in the pay zone. Such information can later augment the reduced data sets to improve the completion strategy and hydraulic fracture design.
This paper describes a case study of a 4-well fracturing campaign in the lower Cleveland sand in Ellis County, Oklahoma. The objective of this project was to compare the completion and production from geometrically stimulated wells against an equal number of wells with an engineered optimization plan. The basic information included drilling data, steering information, and a basic mud and gas log. The optimization on the two engineered wells included an advanced drill cuttings analysis that provided rock texture, mineralogy, and rock properties along the entire length of the lateral. In addition, the drill cuttings were evaluated by a rock laboratory for fluid sensitivity.
The results of this study show a significant improvement in the hydraulic fracturing treatment results. The engineered fractured completions were 70% faster— in particular eliminating screenouts that affected operations in one of the geometrically designed wells. The design process is described and has been extended to include the results of the drill cuttings analysis, and incremental results from fracture operations. These are correlated with the plan wells, and a comparison of the available production data is included in the final evaluation of the technique. The lower Cleveland sand was amenable to using this reduced data set for fracture optimization, and this method may be applicable to similar formations.
Self-Removing Fracturing Plugs: A Study of Initial Adoption in the Williston Basin
Authors: Nichols Matthew , Eis Andrew 
Published: March 2017

Abstract
Research and development of hydraulic fracturing plug materials has shifted to materials that degrade upon exposure to wellbore fluids, thus eliminating the typically necessary post-fracturing millout operations. This paper provides an overview of the field trials and initial commercialization of a dissolvable metal alloy fracturing plug in the Williston Basin. The paper also discusses the alloy’s reaction with wellbore fluids and degradation prediction based on wellbore fluid constituents.
During several months of degradable fracturing plug field trials, performance metrics were established, monitored, and analyzed for each stage of the completion process. Tests were conducted using samples of the alloy submerged in actual wellbore fluids from a given field trial to predict wellbore degradation. The test results were correlated to the field trial results, which helped enable prediction of degradation in future field trials.
The conventional design and mechanics of the degradable alloy fracturing plug allow it to be set similar to the industry-standard composite plugs because no special tools or processes are necessary. More than 1,500 successful runs have been completed in the Williston Basin alone. Installation performance has been predictable since the field trials began; however, estimating degradation time has been more challenging because fluid-related variables are difficult to control. Degradation can vary significantly, even in similar fluids, because of specific fluid constituents’ effects on the reaction that occurs at the plug-fluid interface. The approach of relating test results to field results helps correlate many of these variables and helps identify specific constituents that affect degradation. Strong production figures allowed an operator to skip post-fracturing treatment millout operations in a few cases, thus saving more than USD 200,000 and several days of millout operations in one particular case. Additional field results and tests should help predict with a higher degree of certainty whether a well can be put on production after the fracturing treatment.
This paper summarizes an approach for establishing performance standards, implementing testing methods, and predicting degradation of a degradable alloy fracturing plug designed to help eliminate post-fracturing treatment interventions altogether.
Study and Application of Novel Low Damage Stimulation Technology in Sulige Tight Gas Field
Authors: Yaoyao Duan , Baoshan Guan , Yun Xu , Zhanwei Yang , Yongjun Lu , Zhuhong Tian , Xueliang Yu 
Published: March 2017

Abstract
The Sulige tight gas reservoir is characterized by poor physical properties, tiny pore throats, low fracturing coefficients, high contents of clay minerals and high sensitivity to damages induced by external fluids. To minimize the damages of reservoir induced by fracturing fluids and thereby enhance the well performance, researches were performed on low damage fracturing fluids. By adopting the cellulose modification technology and special crosslinker, a residue-free cellulose fracturing fluid system was developed. This system involves fewer kinds of additives. It can realize crosslinking under acidic conditions without addition of clay stabilizer, and enables the gelatinizer to dissolve fast. Lab tests show that the cellulose thickener may swell and reach 97.2% of its maximum viscosity within 2 min. When shearing at 90°C and 170 s-1 for 90 min, the apparent viscosity of fracturing fluid is 390.2 mPa·s, the surface tension and interface tension of gel-breaking fluid are 24.35 mN/m and 1.05 mN/m respectively, the residue content of fracturing fluid is zero, and the core damage rate is 12.3%. Thus, this cellulose fracturing fluid demonstrates rapid viscosity enhancing ability, high temperature-resistance, high shear resistance, fast and thorough gel breaking and residue-free., making it more suitable for tight gas reservoir. The new system can be prepared easily and conveniently on site. It was applied in 5 wells in East-2 Area of the Sulige Gasfield, with success rate of 100% and with open-flow capacity of 9.5×104 m3/d in production test. Compared with neighboring wells with identical geologic conditions, the average post-fracturing flow-back time for broken glue was reduced by 55%, and the average open-flow capacity was enhanced by 180%. With outstanding performance in productivity enhancement, the new system is worthy of extensive promotion.
In-Situ Poisson's Ratio Determination under Different Deformational Conditions
Authors: Baldino S. , Rafieepour S. , Miska S. Z. 
Published: March 2017

Abstract
Knowledge of in-situ mechanical rock properties is of critical importance for well design and prediction of formation fracturing, including human-induced seismicity. Shahri and Miska (2013) proposed an innovative technique for the estimation of in situ Poisson's ratio. Under the assumption of plane strain, the interference well test was generalized to also find the average in-situ Poisson's ratio. An extension and comparison of this model to several different boundary conditions such as generalized plane stress and uniaxial strain is proposed.
Firstly, the three-dimensional theory of consolidation is applied to formulate the generalized diffusivity equation for a deformable porous medium. This provides us with the coupling between deformation and flow response needed to determine Poisson's ratio from an interference well test. Generalized plane stress, simplified generalized plane stress, uniaxial strain, generalized uniaxial strain, and plane strain with constant horizontal stress assumptions are then applied, resulting in several different values of the estimated Poisson's ratio. The same field data originally analyzed are used to show the main steps of the proposed technique, and to compare its results with that derived in the earlier work.
Estimation of average in situ Poisson's ratio, using different assumptions, provides a means to select the most appropriate model for accurate reservoir deformational behavior. In-situ Poisson's ratio and specific storage capacity, depending on flow-induced stress changes, can also enhance the accuracy of the estimated stress distribution resulting from production/injection. This leads to optimization of well design and formation fracturing.
Evaluating Multiple Methods to Determine Porosity from Drilling Data
Authors: Cedola A. E. , Atashnezhad A. , Hareland G. 
Published: March 2017

Abstract
Porosity can be obtained from drilling data by using different correlations that relate the porosity to the unconfined compressive strength (UCS), which is obtained from drill bit inverted rate of penetration (ROP) models. Knowing the porosity at a given depth can benefit in helping to define the formations being penetrated and to characterize variations in a reservoir, thereby benefitting in selective stimulation. In this paper, previous studies that present methods for calculating porosity from UCS values will be compared and evaluated with sections of porosity that have been calculated from log data taken from three wells in Alberta, Canada. The correlations that will be compared include: Onyia, Sarda, Erfourth, and the UCS-gamma ray methods. The Onyia, Sarda, and Erfourth correlations are previously published while the UCS-gamma ray method correlates UCS in conjunction with the gamma ray at the bit. The porosity values that are found through these correlations are then plotted and their trends compared to each other as well as to the porosity obtained from log data in different sections from the well in Alberta, Canada. This process will help to determine what formation types are best correlated to the individual correlation. Typical drilling data is used in an inverted ROP model to obtain UCS. The UCS and gamma ray values are then taken and related to the porosity through the correlations presented in this paper and compared to the porosity determined from log data. Examining the different correlations that have been analyzed in various types of formations yield information indicating which correlation is best correlated to a specific formation type. The comparison's show that the predictability for some correlations are reasonable for limited datasets and sections of the well. To reasonably predict porosity values for mixed lithologies or shale formations, the integration of gamma log data is necessary. The trends exhibited from the correlations show that the comparison between porosity in shale is better seen when using the integrated UCS-gamma ray correlation. Utilizing the new UCS-gamma ray model seemingly indicates that this useful new method can more accurately predict porosity variations in mixed lithologies and in shale reservoir sections. Bettering stimulation placement as well as minimizing logging in the reservoir can greatly reduce the overall cost of the operation. The improved selective stimulation process could also allow for higher production rates and/or potential reduced stimulation cost, thus increasing overall profit.
Quantification of the Microstructure Heterogeneities of Bakken Shale Reservoirs from Multi-Fractal Analysis
Authors: Liu Kouqi , Ostadhassan Mehdi 
Published: March 2017

Abstract
Unlike the more homogeneous pores in sandstones, the pores structures in the shale formations are heterogeneous and complicated due to the diagenesis and geological processes. The heterogeneous rock pore structures can influence not only the flow properties of the oil and gas but also the mechanical properties. Thus, it is important for us to quantify the heterogeneities of the pore structures in this kind of rocks. In this paper, we used the multifractal theory to analyze the microstructure heterogeneity properties of the samples from Bakken Formation which is a typical unconventional shale reservoir in North America. Based on the study of the scale impact on the multifractal parameters, we proposed the necessity of using the representative elementary area to analyze the pore structures. Finally, we derived the representative elementary area of several samples and compared their heterogeneities.
A Practical Guide to Modern Diversion Technology
Authors: Van Domelen Mary S. 
Published: March 2017

Abstract
Success of a matrix acidizing or fracture stimulation treatment depends upon complete coverage of all zones. The diversion process is used to help ensure that stimulation fluids are distributed across the entire interval to be treated. The diversion method best suited for a particular situation depends on many factors, including the type of well completion, perforation pattern, zonal isolation method, and stimulation technique. Selection of the most appropriate diversion method is also influenced by variations in formation permeability or stress contrasts along the interval to be treated. The purpose of this paper is to provide a historical review of diversion technologies applied in matrix acidizing and hydraulic fracturing treatments and to build upon past experiences to allow optimization of modern diversion practices with self-degrading particulates. Diverter design guidelines will be provided guiding the reader toward the best practices for a) choosing the appropriate base material, b) selecting the correct particle size distribution, c) deploying the diverting agent properly, and d) monitoring the execution of the diverter stages. Laboratory and field data will be provided to supplement the design process.
Enhancing MPD Functionality: Successful Application of Adaptive Intelligent Drilling Software in Deepwater, Offshore and Onshore Operations
Authors: Rostami S.Ameen. Ameen 
Published: March 2017

Abstract
Because of the inherent safety and time-saving capability of managed pressure drilling (MPD), its use is becoming progressively more common in drilling operations. More importantly, MPD is increasingly being considered for any other operations requiring precise pressure control to maintain wellbore integrity in constricted drilling boundaries. The essential need of such a comprehensive system led to the design of innovative MPD software in which integrated smart control logics and intelligent engineering modules manage downhole pressure accurately.
The continuing development of adaptive advanced MPD software, including user interface, integrated models, control algorithm, connection optimization, and detection modules, enable critical decision making for more efficient execution. This MPD software supports pre-engineering operation, post-job analysis, automation of real-time and pressure-sensitive tasks, multiple software engines evaluating limits, and multiple components being controlled in one place.
This paper will discuss the operational details of implementing the new adaptive MPD drilling software in different complex geological reservoirs. The integrated MPD drilling software platform is used in combination with interactive models and surface and downhole data measurement in a unified computing system to enhance real-time analysis of drilling performance. Additional software platform applications deliver the common integration baseline that enables pre-drilling, while-drilling, and post-drilling analyses. The integrated, automated MPD software has been successfully used in several onshore high-temperature/high-pressure (HPHT) wells, deepwater offshore wells (naturally fractured formation), and North Sea wells with narrow drilling windows (where both HPHT and wellbore stability were challenges). This paper discusses the applications and the newest developments in the MPD integrated software to automatically and precisely manage wellbore pressure. The results to be presented include the summary of the planning, while-drilling analysis, and post-drilling analysis of several case studies.
Gas in Riser - The Elephant in the Room
Authors: Vavik D. , Sevillano L. C. , Sangesland S. , Røed B. K. 
Published: March 2017

Abstract
Gas hydrates forming during well control events in deep water plugging kill and choke lines is a risk previously documented (Lage et al. 2002). In this paper a deep water well's temperature profile has been calculated to investigate the forming of hydrates in the wellbore casing and the riser annulus. The calculations show that water-based mud (WBM) has a large potential for cooling down the wellbore during circulation. The cold seawater surrounding the long riser act as a heat exchanger that gradually removes energy or heat from the drilling fluid. The relatively low thermal conductivity for cement will also result in the cement acting as an insulating layer against the formation, leaving the casing wall at a relative low temperature. The study shows that the temperature conditions for forming [BR1]hydrates are likely[BR2] present deep down inside the wellbore casing as well as in the wellhead, the BOP and the drilling riser.
The volume reduction when hydrates are forming may mistakenly be interpreted as loss of mud to the formation and not a result of gas influx to the wellbore. This may have safety implications. [BR3]Gas hydrates forming in the casing wellbore may also change the properties of the WBM since gas hydrates are formed using water from the mud.
The calculations also show that gas hydrates may stay stable in large part of the wellbore casing and the riser annulus and may be transported a long distance to the upper part of the riser and without any significant change in volume. If gas hydrates are transported up the riser, the released gas will expand rapidly upon the melting of the hydrates, resulting in a very limited time for the drill crew to perform the required actions.
Based on the findings in the study the authors recommend that the human factors implications of hydrates in drilling and well control should be further investigated in order to improve overall system safety.
Operational Efficiencies Realized by Integrating Managed Pressure Drilling and Rig Control Systems
Authors: Smith Michael 
Published: March 2017

Abstract
As managed pressure drilling (MPD) has come of age, it is becoming clear that a new approach of integrating MPD into the drilling rig control system is needed. The typical strategy of installing a MPD monitor in the driller's cabin and labeling that "integrated" is not sufficient for achieving the full potential of MPD. Instead, this approach leads to operational inefficiencies and higher potential for making simple mistakes that have significant impact on the operational success of a MPD deployment. This paper will review the factors that need to be considered and study the impact on personnel performance that is critical to a successful integration of MPD and rig control systems.
Assessing Heave-Induced Pressure Oscillations in Offshore MPD
Authors: Strecker Timm , Aamo Ole Morten , Manum Henrik 
Published: March 2017

Abstract
The focus of this paper is to illustrate how a first-principles model of the well hydraulics can be utilised to assess the magnitude of heave-induced pressure oscillations while drilling offshore from floating rigs. Such pressure oscillations are important to consider, as they can violate tight pressure margins.
Based on numerical simulations, we identify situations in which significant downhole pressure oscillations must be expected. We discuss parameters that affect the pressure amplitudes, and illustrate how the simulator is set up to predict the to-be expected pressure oscillations. Such predictions are essential for making an educated decision on whether drilling is possible under given wave conditions and drilling parameters, both when planning a well and in real-time while drilling. We also illustrate how uncertain downhole parameters affect the pressure oscillations, and propose ways to handle the uncertainty in the predictions.
Finally, practical issues such as the estimation of downhole pressure oscillations from on-site measurements, calibration of model parameters, ways to reduce the pressure oscillations via the choke, and the limitations thereof, are discussed.