bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Importance of Asphaltene Deposition Measurements in the Design and Operation of Subsea Pipelines
Authors: Akbarzadeh Kamran , Ratulowski John , Lindvig Thomas , Davies Tara , Huo Zhongxin , Broze George , Howe Richard , Lagers Kees 
Published: October 2009

Abstract
Shell Exploration & Production Company has been operating fields producing asphaltenic fluids in the Gulf of Mexico (GOM) for several years and had previously been unable to accurately predict the extent and location of asphaltene deposition. As a result, well bores and subsea flowlines have in some cases been plugged whereas in other cases it is likely that inhibitor injections have been unnecessarily employed. In this study, a flow-through high-pressure deposition cell was used to measure the deposition rate of asphaltenes from a problematic field in the GOM under realistic conditions of pressure, temperature and composition. The impacts of shear (corresponding to the production rate in the field), residence time of the fluid in the cell, pressure, and chemical injection on the asphaltene deposition rate were investigated. Finally, the importance of these measurements for field production is discussed.
A Successful and Economic Way to Have the Right Professionals
Authors: Harker Andres Reyes , Saavedra Neston F. , Plata Willington A. 
Published: October 2009

Abstract
High Price of oil brought new challenges to oil companies regarding the knowledge management and "humanware" policies. Ecopetrol, through the Research Branch of the company (Instituto Colombiano del Petroleo - ICP), designed and accomplished an aggressive and innovative strategy for creating strong relationship with the universities looking forward to assuring the necessary capabilities and human resources in a very competitive industry.
The first step was the definition of the critical knowledge and topics requiredfor the company to guarantee the future growing and a competitive international position. Themes as well stability, seismic processing, enhanced oil recovery, mature fields development, structural geology, stratigraphy, among others, were defined as key knowledge for the oil industry activity and development in Colombia. Cooperation agreements were signed with the universities for organizing research groups which would work with the following structure: Groups would be composed for undergraduate students from the 4 upper levels (education in undergraduate level in Colombia is structured in 10 periods, six months long each) and postgraduate students, in a sort of pyramidal structure.The group should have leader researchers from Ecopetrol and the university (at least 1 of each institution).Young researchers are recently graduated students, with specific responsibilities in research projects and leading groups of undergraduated studentsEcopetrol would give strategic guidelines and sponsor the projects proposed for the group leading the focus of the invested resources
This initiative started back in 2003, with 10 agreements with different universities. After 5 years of successful operation, Ecopetrol invested in 2008 a sum near to US$4 M in 32 cooperation agreements pointing to research projects of the company; 193 undergraduate and 185 postgraduate students are part of the research groups. More than 90 technical solutions have been provided to Ecopetrol and 8 software solutions were designed and currently are in operation in the company.
In addition to these results, the most important success of the program is the people; Ecopetrol have the possibility to select the educated professionals in strategic branches of knowledge that have supplied the company with the necessary human force to face the challenge of becoming and international competitor.
A Numerical Study of Performance for Tight Gas and Shale Gas Reservoir Systems
Authors: Freeman C. M. , Moridis G. , Ilk D. , Blasingame T. A. 
Published: October 2009

Abstract
Various analytical, semi-analytical, and empirical models have been proposed to characterize rate/pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a few analytical models as well as a small number of published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems, particularly regarding the dominant flow regimes and whether or not reservoir properties/volume can be estimated from well performance data.
We constructed a fit-for-purpose numerical simulator which accounts for a variety of production features pertinent to these systems — specifically: ultra-tight matrix permeability, hydraulically fractured horizontal wells, multiple porosity and permeability fields, and desorption. These features cover the production mechanisms which are currently believed to be relevant in tight/shale gas systems.
We employ the numerical simulator to examine various tight/shale gas systems and to identify/illustrate the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as maps of pressure distributions.
We use pressure maps to demonstrate the various flow regimes and their transitions in tight gas systems. In a typical tight gas system, we illustrate the initial linear flow into the hydraulic fractures (i.e., formation linear flow), transitioning to compound formation linear flow, and eventually transforming into elliptical flow.
We explore variations of possible shale gas system models. Based on diffusive flow (with/without desorption), we show that due to the extremely low permeability of shale, the flow behavior is dominated by the extent of and configuration of the fractures.
This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.
Installation and Operational Performance of Horizontal Solid Expandable Openhole Production Liners in Maximum Reservoir Contact Wells – Case Histories
Authors: Sanders Tom , Zhou Shaohua , Aramco Saudi , York Patrick , Joulaud Thomas , Teo Jeffrey , Gandikota Raju 
Published: October 2009

Abstract
Solid expandable liners have been used extensively over the past 10 years as drilling liners in the beginning to production liners in the recent years, where the expandable liner may become differentially or mechanically stuck as soon as it reaches the end of the planned wellbore section. This environment requires the liner to be cemented and expanded in one of the most (if not the most) challenging well conditions it can be subjected. The expandable liners discussed in this paper so far have shown most promising and successful field application status as production liners.
When an expandable liner that is not differentially stuck is expanded using a swage, it typically "shrinks" in length as it expands in diameter as part of material balance physics. This shrinkage is typically 4 to 6%. That is, if a 1,000 ft liner is expanded 5% in diameter, the expanded length would be reduced to ~950 ft. To compensate for this shrinkage, an additional length of liner is run to ensure that the final length of liner required is delivered. However, when the expandable liner becomes differentially stuck or cannot move along the length of the wellbore during expansion, it cannot gain the material for its growth in diameter from the liner's length. Therefore, the material volume change required is accommodated within the liner's wall and its connectors. This environment is considered one of the most strenuous a solid expandable liner can be subjected to during expansion.
By combining insightful engineering with a stringent qualification regime of the expandable system and the tubulars and connectors that it uses, solid expandable production liners can be installed successfully that will service these types of challenging wells.
While extensive engineering and lab testing of an expandable system is critical, the ultimate testing is in multiple field applications to best develop effective reservoir sweeping of a mature field. Several case histories of field installations will be reviewed in this paper. The installation, zonal isolation, and tubular performance of these liners will be evaluated and reviewed using downhole tubular inspection logs, observed installation phenomenon, and performance over time. This empirical data will give the potential end users fundamental knowledge and good case history information on how to best qualify and use solid expandable liners for the ultimate benefit of gaining more oil production and reducing overall well cost.
New Slickline Smart-Release Tool Mitigates Wire-Recovery Issues in Extreme Well Conditions
Authors: Clemens Jack , Moore Darrell , Schram John , Foster Jerry , Garrett Johnnie 
Published: October 2009

Abstract
Traditionally, when wells in extreme environments required service, slickline, which had always been considered as the most cost-effective service option, was unable to provide the services because the available slickline tool options could not maintain integrity in the extreme well environments now being explored and developed. To address the requirements of the new scope of conditions in extreme environments, new methods that would meet a greater scope of needs were developed. The innovations include prejob wire-tension-modeling software and a state-of-the-art timed-release tool that provides successful intervention in difficult scenarios that normally could not have been considered as slickline candidates.
This paper will discuss these developments and how they have enabled slickline to be a more cost-efficient alternative for the operations that had to be performed by other service options when intervention was required in extreme depths or in or highly deviated wells.
A tool that can be timed to release the wire from the tool string at the rope socket without surface intervention has been developed to reduce the risks associated with stuck strings and dropping of conventional wire cutters. In addition, pre-job wire-tension modeling software is now available. How the newly developed slickline techniques can be used to mitigate the risks associated with the challenges created by the extremely deep and highly deviated wells will be discussed along with the enhanced cost efficiency and safety provided by these innovations. Implementation of the smart-release tool into the tool string will also be discussed.
Balancing Lithology and Low-Pressure Hydrocarbon Effects: Evaluation of Low-Pressure Reservoirs Utilizing Magnetic Resonance in the Alaska Cook Inlet
Authors: Toumelin Emmanuel , Voorhees Brent , Shafer David , Jebutu Segun , Manning Michael , Coope Daniel 
Published: October 2009

Abstract
Two mature offshore fields, Granite Point Field and Grayling Gas Sands, were recently re-drilled in the Alaska Cook Inlet where oil and gas are accumulated in thousands of feet of lower-Tertiary, stacked fluvial sand/shale/coal cycles. Common challenges in the two fields suggested their characterization could be improved with nuclear magnetic resonance (NMR) logging, namely: detection of conglomeratic sands, deciphering of complex neutron/gamma-ray responses, quantification of gas saturation, and even detection of low-resistivity pay. However, these formations exhibit properties that limit classic NMR logging interpretation, including abnormally high T1/T2 ratio, high free-fluid T2 cutoff, and low pore pressure. Low-gradient LWD NMR was employed to evaluate the new wells and solved these challenges.
Given the low gas pressure, traditional gas identification using dual wait times or high-relaxation cutoff was ineffective and a density/magnetic resonance (DMR) method was used to quantify gas in place. This method led to substantial porosity corrections, compared to usual practices. Low-resistivity gas zones were also clearly delineated regardless of gamma-ray and neutron lithology effects. Main lithology (sand, conglomerate) could then be inferred from the corrected formation properties by comparison with documented trends from legacy core data.
Accuracy of Fluid Property Estimates for Calculating Seismic Properties
Authors: Sutton Robert P. , Hamman Jeffry G. 
Published: October 2009

Abstract
Modeling seismic responses in reservoir rock requires the accurate determination of fluid density, modulus or its reciprocal, the adiabatic compressibility and acoustic velocity. The geophysics community has developed methods to estimate these properties for subsurface oil and gas accumulations at reservoir conditions. Similarly, the engineering community has developed methods to estimate density and isothermal compressibility. The goal of both groups is the accurate characterization of these PVT properties at elevated pressure and temperature especially at the extreme conditions encountered in frontier reservoir environments and newer discoveries and for the quantitative interpretation of 4D seismic. A large and diverse database consisting of 1099 worldwide oil PVT reports with 11,960 density measurements was used to evaluate the various fluid property correlations. The database encompasses oil with API gravity ranging from 10.6-63 along with solution gas-oil ratios of 5-4,631 SCF/STB resulting in saturation pressures ranging 60-10,326 psia at temperatures over the range 50–332 °F. The PVT reports provide a measure of isothermal compressibility; therefore, heat capacity ratio must also be addressed in the comparison with adiabatic compressibility methods. In this work, gas property correlations were tested against methane PVT data derived from the National Institute of Standards and Technology (NIST) which ensured consistent results over a wide range of pressure and temperature conditions. The principle of corresponding states can then be used to examine the suitability of using these correlations for gas-condensate systems. Results of the study detailing the accuracy of the oil and gas PVT correlations are presented.
New Class of Logging While Drilling Tools Extends Possibilities for Trajectory and Stratigraphic Control While Drilling in Deep, HT/HP Wells
Authors: Mazzoni S. , Borghi M. , Affleck G. , Christie R. , Troiano M. 
Published: October 2009

Abstract
The positive experience and results obtained by using a new class of high temperature / high pressure (HT/HP) logging while drilling (LWD) tool in a slimhole (5-3/4-in.) exploration well in Italy's Po Valley opens new possibilities for trajectory and stratigraphic control while drilling in deep, HT/HP wells. Using the LWD suite, the operator was able to acquire real time, continuous temperature, gamma ray and resistivity data for analysis and correlations at 180°C (356°F) and 16,780 psi – conditions previously unachievable. As a result, the operator pinpointed the stratigraphic position of a main direct fault that raised the upper reservoir above the prognosis estimation and was able to: achieve critical placement of the casing shoe to avoid a well control hazard posed by drilling into a partially depleted reservoir;drill continuously without having to pull the bottomhole assembly out of the hole and change bit types for better, unaltered cuttings; andidentify a carbonate sequence in the lower section, which ultimately led to the decision to plug and abandon the lower section and produce the upper reservoir, with very good results.
Real time annular temperature measurements provided accurate temperature data for mud program optimization and operational considerations that are not usually available in exploration wells.
This paper will discuss the characteristics and operating limitations of the Villafortuna-Trecate HT/HP field; the objectives of the Cascina Cardama 1 Dir well; the LWD planning and implementation, and the operations, logs and results.
Based on the experience and results of this well, the operator will continue to use the high temperature LWD suite to drill future wells and projects.
Predicting Relative-Permeability Curves Directly From Rock Images
Authors: Silin Dmitriy , Patzek Tad 
Published: October 2009

Abstract
The objective of this study is determination of relative permeability curves from an analysis of the pore space geometry. The main assumptions are that the capillary pressure determines the fluid distribution and the rock is water-wet. Maximal inscribed spheres computations characterize the portion of the pore space occupied by each fluid at a given saturation. Numerical solution of the Stokes equations evaluates the pore-scale flow field, which is averaged to estimate the permeability to each fluid. The computed relative permeability curves are in good agreement with published data.
The input for the proposed procedure can be either a computer tomography image of a sample of the rock of interest, or a computer-generated image based on depositional simulations. Partitioning of the entire domain into parts significantly improves the convergence and makes feasible implementation of the computational procedure on a desktop computer. The stability of the results with respect to the choice of computational parameters makes the proposed method suitable for routine applications. The model admits generalizations relaxing the requirement of water wetness of the rock. This model can be applied to evaluate the evolution of the rock flow properties under deformation, damage, mineral dissolution and precipitation.
Development of a Successful Chemical Treatment for Gas Wells with Water and Condensate Blocking Damage
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. 
Published: October 2009

Abstract
Significant productivity loss occurs in gas condensate reservoirs due to condensate and water accumulation near the production well. Our experimental study shows that gas relative permeability decreases by more than 95% due to liquid blockage (high water saturation along with condensate accumulation) and the reduction is even more pronounced in presence of mobile water.
Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid blocking in gas condensate reservoirs. The treatment is composed of a non-ionic polymeric fluorochemical in a glycol/alcohol or glycol ether/alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability. It also reduces the liquid trapping in pores, which increases the relative permeability to oil or condensate and makes the removal of water blockage from treated zone easier. Selection of solvents to deliver the fluorochemical to the rock surface is critical to the success of the treatment, especially in the presence of high water saturation and high salinity brine.
The treatment improved the gas and condensate relative permeabilities by a factor of about 2–4 on liquid blocked outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing coreflood experiments at reservoir conditions. The treatment also shows good durability against flowing gas, condensate, brine and solvent.
We have developed a chemical treatment that shows great potential to increase production from liquid blocked gas wells with relatively small treatment volumes since only the near-well region needs to be treated.
A Next-Generation Reservoir Simulator as an Enabling Technology for a Complex Discrete Fracture Modeling Workflow
Authors: Lim Kok-Thye , Hui Mun-Hong , Mallison Bradley 
Published: October 2009

Abstract
We present an innovative workflow for reservoir characterization, gridding, discretization, and simulation of discrete fractures embedded within a single-porosity continuum. This discrete fracture modeling (DFM) workflow provides the capability to realistically model the impact of fractures on recovery without incurring the simplifying assumptions of traditional dual-porosity models. We represent the matrix of the unstructured DFM using 3D polyhedral cells including tetrahedra, pyramids, and prisms. The fractures are represented as polygonal interfaces between matrix cells.
The workflow is enabled by a next-generation reservoir simulator that is designed for robust solution of unstructured grid models. The simulator supports parallel computation on distributed and shared memory machines without manual user intervention. The efficiency of the simulator is due primarily to a parallel linear solver that is designed specifically for unstructured grids. This results in a very efficient and robust reservoir simulator for highly heterogeneous DFMs.
We demonstrate the practicality of this technology by performing a design of experiments (DoE) study that involves a suite of sector models representing multiple discrete fracture realizations of an actual carbonate reservoir. We also show the feasibility of a full-field simulation including over ten thousand discrete fractures, more than a hundred wells, and 3.65 million simulation cells. These simulations are challenging due to the high contrast in matrix and fracture properties, multiphase flow, and the inclusion of complex physics (e.g., rapid gravity segregation in fractures, first- and multi-contact miscibility).
The successful application of the DFM workflow is largely due to the availability of the next-generation technology for reservoir modeling. We could not perform this work using existing simulation technologies designed for structured grids. Our DFM work facilitated the understanding of recovery mechanisms and contributed to business decisions toward optimal development of the carbonate reservoir.
Geomechanical Modeling Helps Designing the Wells in the Neuquén Basin, Argentina
Authors: Araujo Ewerton , Casalis Daniel , Ward Chris , Sheridan Judith 
Published: October 2009

Abstract
This paper shows how a geomechanical model helped to reduce risks and non-productive time experienced in the past in a field in the Neuquén Basin (Argentina) operated by Petrobras Energia S.A. (PESA). Tight hole and stuck pipe were common problems in spite of the tight and strong formations in the field. Gas inflows were also experienced when drilling through the overpressured formations. All these events made the decision of building a geomechanical model for the field in order to optimize the drilling time.
Pore pressure, stresses and mechanical rock properties were constrained based on good quality data set from eight wells. After that, the geomechanical model was validated using the caliper data and drilling experience. A key part of the model building was the estimation of pore pressure using wireline logs, gas inflows during the drilling, production data and minifrac tests. Overpressured zones were identified improving the design of the casing depths for new wells, minimizing the risks of kicks while maintaining the wellbore stability. Based on the remaining uncertainties of the model, an update phase was recommended to be done after the collection of new data such as image logs in the well to be drilled.
After drilling the new well using the recommendations of the geomechanical model, the drilling experience showed that the well was drilled almost without non-productive time (NPT) through the same formations where in the past tight holes and stuck pipes were experienced. A good image data collected in the drilled well showed that the breakouts stayed below the catastrophic limit, confirming that the mud weight was correctly recommended in the phase 1, maintaining the wellbore stability without reducing the ROP. Also, the observed breakout orientation and width confirmed the orientation and magnitude of the maximum horizontal stress constrained in the phase 1.