bluuebunny/crossref_metadata_2025_split huggingface dataset:
Video Production Logging and Polymer Gel Yields Successful Water Isolation in the Fayetteville Shale
Authors: Brady J. , Shattuck D. , Parker M. , Sramek C. , Jones A. , Gould J. , Jayakumar S. 
Published: June 2014

Abstract
Implementation of video production logging in conjunction with the use of high molecular weight polymer gels, has led to successful water isolation operations in the Fayetteville shale. The dry natural gas field, located in northern Arkansas, is a horizontal play with the wells cased, cemented, and completed with multi-stage slickwater fracture stimulations using perforation and plug technology (Harpel, 2012).
Accurate detection of extraneous water entry points along the wellbore is vital for precise water isolation treatment, while still protecting the hydrocarbon producing intervals. Conventional production logging tools have been utilized in the past but proved to be expensive, due to the wellbore configuration, and imprecise because of the horizontal trajectory and debris encountered in the wellbore, with the debris generally rendering the spinner tool inoperable. Video logging tools, deployed in combination with high frequency temperature and pressure gauges, have considerably improved identification of water entries along the wellbore. In addition, the use of a smaller logging assembly has also drastically reduced workover costs by permitting logging through the existing 2-3/8" OD production tubing whereas conventional production logging required the removal of the production tubing due to size limitations. By maintaining this wellbore configuration the flowing conditions remain undisturbed and increase the accuracy of the production log.
Based on video production log results the proper water isolation operation is subsequently selected. While cement squeezes and mechanical isolation tools have been applied successfully in horizontal wells to isolate inflow from water producing perforations, they are limited in their applications due to the wellbore configuration and operational costs. Recently, treatment of water producing perforations with chrome (III) carboxylate acrylamide polymer (CC/AP) gel technology has allowed selective treatment in additional sections of the wellbore. These gel treatments have yielded strong results by isolating water production and increasing gas production by reducing the flowing bottomhole pressure. Evaluation and selection of the appropriate polymer gel is discussed along with design considerations and implementation.
Multiphase Compositional Modeling in Small-Scale Pores of Unconventional Shale Reservoirs
Authors: Alharthy Najeeb S. , Nguyen Thanh N. , Teklu Tadesse W. , Kazemi Hossein , Graves Ramona M. 
Published: June 2014

Abstract
Compositional modeling of hydraulically stimulated naturally fractured liquid-rich shale (LRS) reservoirs is a complex process that is yet to be understood. The flow and multiphase mass transfer in the nano-, meso-, and macro-scale pores, as in Eagle Ford, Woodford and Bakken is of great interest. Understanding the production mechanisms from such reservoirs is crucial in the overall effort to increase the ultimate hydrocarbon production. Thus, we focused on deciphering the physical fundamentals of various recovery mechanisms via reservoir modeling. The starting point was examining the phase behavior issues in unconventional reservoirs. Specifically, we constructed phase diagrams using a new correlation to shift the critical properties of components in the nano and meso-scale pores. The correlation was applied to three recently published Eagle Ford fluid samples. The new phase behavior correlation was used in a dual-permeability compositional model to determine the nature of pore-to-pore flow and, eventually, the hydrocarbon production from wells. In the simulation models we allowed for the phase behavior differences between fracture and matrix and included a multi-level flow hierarchy from matrix (nano, meso, and macropores) to fractures and finally to the well. To make computation accurate we resorted to a series of detailed logarithmic local grid refinement (LS-LGR) in various strategic subdomains in the matrix and fracture.
As a result of this modeling study, we have concluded several reasons why hydrocarbon fluids can move in the shale reservoir nano, meso, and macro-scale pores and why we are able to produce from such low-permeability reservoirs. For instance, favorable phase envelope shift of hydrocarbon mixtures in the nano- and meso-scale pores is one of the contributing factors to economic production in gas-condensate and bubble-point systems. Also noted, when the phase envelope is crossed in gas-condensate systems, a large gas-to-oil volume split in the nano, meso, and macro-pores plays a crucial role in hydrocarbon recovery during depletion. For the bubble-point oil region, the low viscosity of the liquid phase and the delay in gas bubble evolution appears as the main reason for favorable oil production. Furthermore, ‘rubblizing’ the reservoir in the vicinity of hydraulic fractures creates another favorable environment for improved drainage, which is why multi-stage hydraulic fracturing is so critical in successful development of shale reservoirs.
Value of Competency and Value of Competency Assessment
Authors: Nieman Timothy L. , Schuyler John , Ford Brett J.. 
Published: June 2014

Summary
What is the value of a competent engineer? How can we be sure that an engineer is actually qualified? Because the big crew change progresses and because regulators worldwide are beginning to require operators to assure the competency of people working in petroleum operations, these questions are becoming increasingly important. We present an approach to address these questions by looking at the value of competency and competency assurance with probabilistic models.
Valuing competency improvement is a value-of-control (VOC) problem, common in such areas as project risk management and risk-based maintenance. Value-of-information (VOI) problems are similar. We demonstrate how to calculate VOC and VOI with decision trees and Monte Carlo simulation. We selected well design as the example application throughout.
The value of a competency assessment is first demonstrated with a decision-tree VOI analysis. With input judgments that we believe are reasonable, the analysis shows that competency assessments are likely underused.
A more detailed well life-cycle model uses Monte Carlo simulation for the stochastic (i.e., probabilistic) calculations. Here, we illustrate a model of training, a well-design process, and multiple review and execution stages during drilling, completion, and production operations. The model features a competency scale, and VOC is shown by valuing incremental competency improvements and an optional peer review. Another VOI example is competency assessment for a junior engineer.
Similar simulation models can help management optimize decisions involving staffing, type and days of structured training, work-process design, and project-design review stages. In addition to reducing the chance and impact of defective engineering, assessments provide important feedback to the engineer as learner, tools for planning training and development, organizational learning, risk management, construction, and safe operations.
We show that VOI and VOC analyses—long used for exploration decisions—can be applied throughout the information processes used in planning and managing processes.
Characterizing Hydraulic Fracturing With a Tendency-for-Shear-Stimulation Test
Authors: McClure Mark , Horne Roland 
Published: June 2014

Summary
The classical concept of hydraulic fracturing is that a single, planar, opening mode fracture propagates through the formation. In recent years, there has been a growing consensus that natural fractures play an important role during stimulation in many settings. There is not universal agreement on the mechanisms by which natural fractures affect stimulation, and these mechanisms may vary depending on formation properties. One potentially important mechanism is shear stimulation, in which increased fluid pressure induces slip and permeability enhancement on pre-existing fractures. We propose a tendency-for-shear-stimulation (TSS) test as a direct, relatively unambiguous method for determining the degree to which shear stimulation contributes to stimulation in a formation. In a TSS test, fluid injection is performed while maintaining the bottomhole fluid pressure slightly less than the minimum principal stress. Under these conditions, shear stimulation is the only possible mechanism for permeability enhancement (except, perhaps, thermally induced tensile fracturing). A TSS test is different from a conventional procedure because injection is performed at a specified pressure (rather than a specified rate). With injection at a specified rate, fluid pressure may exceed the minimum principal stress, and it may cause tensile fractures to propagate through the formation. If this occurs, it will be ambiguous whether stimulation was because of shear stimulation or tensile fracturing. Maintaining pressure less than the minimum principal stress ensures that the effect of shear stimulation can be isolated. Low-rate injectivity tests could be performed before and after the TSS test to estimate formation permeability. An increase in formation permeability would indicate that shear stimulation has occurred. The flow-rate transient during injection may also be interpreted to identify shear stimulation. Numerical simulations of shear stimulation were performed with a discrete-fracture-network (DFN) simulator that couples fluid flow with the stresses induced by fracture deformation. These simulations were used to qualitatively investigate how shear stimulation and fracture connectivity affect the results of a TSS test. Two specific field projects are discussed as examples of a TSS test, the Enhanced Geothermal Systems (EGS) projects at Desert Peak, Nevada, and Soultz-sous-Forêts, France.
Offshore Field Application of a Low Corrosive Fluid Designed for De-Scaling of Well with ESP Completion
Authors: Bakar H. B. , XianLung I. C. , Nadzri M. Z. , Zaini M. A. , Jaafar J. B. , Hirman M. , Nasr-El-Din H. A. , de Wol C. A. 
Published: June 2014

Abstract
The applications of both inorganic and organic acids are to dissolve scales, remove filter cakes and increase the permeability of carbonate and sandstone formations, during processes like de-scaling, completion and stimulation. Often in sandstone mineral acid treatments have hidden costs from logistics, handling and failure to meet performance targets.
The use of a novel low corrosive chelating agent, glutamic acid N, N-diacetic acid (GLDA), instead of hydrochloric acid, was evaluated to remove calcium carbonate and iron scale depositions found in Well A's downhole electrical submersible pump system and near wellbore area at elevated temperatures and pressures. Besides scaling issues, high H2S concentration, up to 300ppm, were also detected in this well.
Extensive lab studies were conducted to determine the chemical's compatibility with the ESP components, dissolution effectiveness of the collected downhole samples and corrosion properties on carbon steel tubulars in the presence of hydrogen sulphide gas. The results proved that the chemical was able to dissolve more than 95% of calcite and iron scales without damaging the cables and elastomers of the ESP after 24 hrs soaking at reservoir temperature.
The offshore treatment application did not require chemical specialist on-board or additional additives such as corrosion inhibitors, intensifiers, iron control agents, etc. Nor did it require a large footprint to place the chemical on the platform. The chemical was bullheaded easily through annulus and tubing without having to pull out the pump. The cost savings of this rigless intervention is estimated to be USD 2mil. The success of this treatment was realized by additional gain of 112 bopd and the H2S concentration was reduced to 10 ppm.
The field application data, along with the lab data, confirms that the GLDA based solution is an effective de-scaling and stimulation fluid that is gentle to various types of well completions, safe to handle, and cost effective to use. This paper highlights the successful use of the GLDA in contributing to the much improved well productivity focusing on the lab studies, operational considerations and production performances of Well A.
Mass Transfer on Multiphase Transitions in Low-Temperature Carbon-Dioxide Floods
Authors: Okuno R.. , Xu Z.. 
Published: June 2014

Summary
Mixtures of reservoir oil and carbon dioxide (CO2) can exhibit complex multiphase behavior at temperatures typically less than 120°F, in which a third CO2-rich liquid (L2) phase can coexist with the oleic (L1) and gaseous (V) phases. The three-phase behavior is bounded by two types of critical endpoints (CEPs) in composition space. The lower CEP (LCEP) is a tie line in which the two liquid phases merge in the presence of the V phase, and the upper CEP (UCEP) is a tie line in which the L2 and V phases merge in the presence of the L1 phase. Slimtube tests reported in the literature show that low-temperature oil displacement by CO2 can result in the high displacement efficiency of more than 90% when three phases are present during the displacement. The nearly piston-like displacements can be quantitatively reproduced in numerical simulations when the CEP behavior is properly considered. However, it is uncertain how multicontact miscibility (MCM) is developed through the interaction of flow and three-hydrocarbon-phase behavior.
This research presents a detailed analysis of mass conservation on multiphase transitions between two and three phases for the limiting three-phase flow, where the L1 phase is completely displaced by the L2 phase on the LCEP. The analysis indicates that interphase mass transfer on multiphase transitions occurs in the most-efficient way for MCM development. Simple analytical conditions derived for MCM through three phases are applied to 1D fine-scale simulations of CO2 floods by use of four and more components. Results show that the MCM conditions are nearly satisfied when the effect of numerical dispersion is small. MCM is likely developed through three hydrocarbon phases on the LCEP in the cases studied. This is consistent with analytical solutions of water and gas injection presented in the literature, in which MCM is developed on a CEP for the aqueous, V, and L1 phases. For MCM cases in this research, the L2-V two phases are present upstream of the miscible front if the composition path does not go through the UCEP tie line. However, they also can be miscible on the non-L1 edge of the UCEP tie line if the MCM composition path goes through it.
Three-phase flow gradually changes to two-phase flow with varying pressure in the presence of numerical dispersion. It is shown that interphase mass transfer on multiphase transitions becomes less efficient during the change until the three-phase region completely disappears.
Gas Condensate Well Unloading Critical Rate
Authors: Alamu Mhunir Bayonle 
Published: June 2014

Abstract
Profile of critical rate for 106 vertical wells producing from high pressure formations has been used to determine an unloading critical rate for well producing gas and condensate. The evaluation involved loaded, questionable and unloaded wells. When this data was compared with experimental data obtained from flow loop where liquid loading condition was investigated, it was observed that any gas condensate well producing above a critical rate of 12 MMSCF/D will produce in an unloading manner.
OLGA, a 3-phase transient multiphase flow simulator was used to confirm the conclusion of well test result. Four gas condensate wells were investigated out of 106 well tested at field conditions - one unloaded; one questionable and two loaded. Results of the simulation confirmed the ‘unloaded’ well was actually producing freely in a stable manner at the wellhead. The ‘questionable’ well was found to be to be producing in churn flow regime characterized by certain degree of instability. The two ‘loaded wells’, on the other hand, were found to be producing but characterized with mild and severe flow instability at the wellhead. A loaded well simulated with 12 MMSCF/D production rate produced in a stable manner.
Three of the wells selected for study had production tubing depth greater than 10,000ft. to study effect of flow development length on liquid loading behaviour of gas condensate well. A modified Froude number based on production tubing depth and entrained liquid fraction in the gas stream showed that a gas condensate is most likely to be loaded if operated below a value of 1000.
Uncertainty Evaluation of Wellbore Stability Model Predictions
Authors: Udegbunam John Emeka , Aadnøy Bernt Sigve , Fjelde Kjell Kåre 
Published: June 2014

Abstract
There is an increasing concern in the oil and gas industry regarding wellbore stability problems. The need to improve well operations becomes more imperative as the operators move towards more challenging and harsher environments such as ultra-deep waters and high-pressure and high-temperature (HPHT) fields.
Different inconsistencies affect many previous wellbore stability analyses, resulting in incorrect results, or results that cannot be extended to other well configurations by well planners. Typical wellbore fracture and collapse models provide single-point estimates of the geopressures. The model input data may be uncertain. Failure to capture these uncertainties has led to poor predictions.
The purpose of this work is to investigate typical fracture and collapse models with respect to uncertainties in the input data with a stochastic method. Uncertainties in the input data, which include in-situ stresses, rock strength data, and pore pressure will be evaluated, to show how these contribute to the cumulative uncertainties in the model predictions.
In this approach, the input parameters are assigned appropriate probability distributions. The distributions are then applied in the wellbore stability models. By means of Monte Carlo simulations, the uncertainties are propagated, and the histograms of the outputs are generated. Two types of distributions—triangular and uniform—are applied, to see how the choice of the input-parameter distributions will influence the model predictions.
Sensitivity analysis is also carried out. This is to ascertain the most significant input parameters, which are largely responsible for the cumulative uncertainties or variabilities in the critical fracturing and collapse pressures.
The proposed methodology can help in reducing many drilling problems such as circulation loss, stuck pipe, and well collapse. As a result, the industry may save much non-productive time. In addition, well planners will have improved information to make critical decisions.
How Farmers, Graziers, Miners, and Gas-Industry Personnel See Their Potential for Coexistence in Rural Queensland
Authors: Everingham J.. , Collins N.. , Rifkin W.. , Rodriguez D.. , Baumgartl T.. , Cavaye J.. , Vink S.. 
Published: June 2014

Summary
The rapid expansion of the coal-seam-gas (CSG) sector in Queensland has fueled debate on the sector's contributions to community sustainability in a rural economy dominated by the farming of food and cotton, cattle grazing, coal mining, and a modest level of tourism. For example, will the impacts of CSG extraction on surface and groundwater have sustained negative impacts on the growing of grain, and if so, what should one expect of the CSG industry today?
The intensity of debate is accompanied by an array of operating conditions placed on CSG projects by the state government, extensive media coverage, and a focus on what it takes to maintain a “social license to operate.” Such a context is a challenge for resource companies committed to sustainability principles and to contributing to the social, economic, and institutional development of the communities in which they operate as well as to the conservation of biodiversity and integrated approaches to land-use planning.
In this context, our research explored perceptions of the social and environmental impacts in two local government areas of rural Queensland. We surveyed and interviewed stakeholders affected by—and/or influential in—decision making and the management of mining, CSG extraction, and agriculture in these areas. We asked their views on the state of the environment, the economy, social fabric, human capital, and local infrastructure, comparing today to 5 years ago. Their responses reveal how this contested arena harbors “wicked” problems: issues that are hard to formulate in simple terms and in which every potential solution has irreversible consequences. Our findings suggest further that the successful coexistence of multiple industries and a social license to operate for CSG companies depend on effective management by resource companies, and by regulators, of operating practices, off-site impacts, and the distribution of benefits.
Simulation of Hydrate Dynamics in Reservoirs
Authors: Vafaei M.T.. T. , Kvamme B.. , Chejara A.. , Jemai K.. 
Published: June 2014

Summary
Gas hydrates in reservoirs are generally not in thermodynamic equilibrium, and there may be several competing phase transitions involving hydrate. Formation of carbon dioxide (CO2) hydrates during aquifer storage of CO2 involves roughly 10 vol% increase compared with groundwater. Dissociation of hydrate toward undersaturated fluid phases involves the same level of contraction. Hydrate phase transitions are generally fast (scales of seconds) compared with mineral dissolution and precipitation, and it is unlikely that a time-shifted explicit coupling to geomechanical analysis will be able to capture the appropriate dynamic couplings between flow and changes in stress. The need for geomechanical integrity of the storage site therefore requires a reservoir simulator with an implicit solution of mass flow, heat flow, and geomechanics. And because CO2 involved in hydrate is also involved in different geochemical reactions, we propose a scheme where all possible hydrate formation (on water/ CO2 interface, from water solution, and from CO2 adsorbed on mineral surfaces) and all different possible dissociations are treated as pseudoreactions, but with kinetics derived from advanced theoretical modeling. The main tools for generating these models have been phase-field-theory (PFT) simulations, with thermodynamic properties derived from molecular modeling. The detailed results from these types of simulations provide information on the relative impact of mass transport, heat transport, and thermodynamics of the phase transition, which enable qualified simplifications for implementation into RetrasoCodeBright (RCB) (Saaltink et al. 2004). The primary step was to study the effect of hydrate growth or dissociation with a certain kinetic rate on the mechanical properties of the reservoir. Details of the simulator and numerical algorithms are discussed, and relevant examples are shown.