bluuebunny/crossref_metadata_2025_split huggingface dataset:
Correlations between NMR T2-D Responses and Relative Permeability from Micro Xray-CT Images
Authors: AlGhamdi Tariq M. , Arns Christoph H. 
Published: October 2012

Abstract
NMR relaxation measurements are routinely used in the petroleum industry to estimate permeability and to partition fluids to estimate irreducible water saturation. The shape of the relaxation time distribution is controlled by many mechanisms like pore-coupling in the presence of heterogeneity, internal gradient effects, and signal to noise ratio. However, given an anchoring of the relaxation time distribution, the logarithmic average of the NMR T2 distribution is a relatively robust measure and for rocks where a correlation between pore and throat size exist, a reliable estimate of permeability can often be made. In this work we utilize high resolution X-ray CT images Berea and Bentheimer sandstone and simulate the NMR relaxation-diffusion responses for the case of drainage by a non-wetting fluid at different magnetic field strength (2MHz, 12 MHz, and 400 MHz), calculating internal magnetic fields explicitely. The T2-D responses are projected onto the relaxation axis for each fluid and the SDR model used to predict absolute and relative permeabilities. The resulting correlations between NMR response and relative permeability are surprisingly strong. In particular, reasonable correlations exist between lattice Boltzmann derived relative permeability and NMR estimated relative permeability even for the effective permeability of the oil. This suggests that internal fields help in establishing a surface related/weighted relaxation mechanism for the non-wetting fluid. This methodology allows testing the applicability of SDR type relative permeability estimates for the purpose of log analysis. A variety of cross-correlations including resistivity information can be considered and correlations between relative permeability and NMR response are optimized by finding the best NMR acquisition sequence and interpretation (e.g. choosing optimal cut-offs).
Eagle Ford Shale: Hydraulic Fracturing, Completion, and Production Trends: Part II.
Authors: Centurion Sergio , Cade Randall , Luo Xin Lucy 
Published: October 2012

Abstract
The Eagle Ford Shale, as one of the most active unconventional reservoirs in the US, began heavy development in 2009. One of the attractive aspects of the Eagle Ford, which has heightened interest and helped to accelerate development, is substantial liquids production, along with solution gas. But the resultant multiphase fluid production, along with reservoir heterogeneity, typical of most unconventional reservoirs, adds complexity and risk to development, especially for the completion.
One technique that has the potential for reducing risk is learning from historical completion trends. Even though the Eagle Ford play is quite new, more than 3,000 horizontal wells have been drilled and all have been hydraulically fractured. The resultant large and growing data resource invites data mining to uncover trends and insights.
The ground work was laid in SPE 149258, which summarized 1,082 fracturing stages in 80 Eagle Ford well. This paper extends that analysis to more than 3,000 Eagle Ford fracturing stages in more than 200 wells. Metrics of completion types, volumes, and efficiencies are analyzed. In addition, the analysis is extended to production data and chemical fracturing additives. The entire data set is mapped in an effort to understand anomalies and trends. As the successful development of this reservoir has relied in the combination of horizontal drilling, multistage completions and hydraulic fracturing, the results should be valuable for understanding and optimizing completions in the Eagle Ford and similar shales.
Hydraulic Fracture Geomechanics and Microseismic Source Mechanisms
Authors: Warpinski N. R. , Mayerhofer M. J. , Agarwal K. , Du J. 
Published: October 2012

Abstract
Interpretation of microseismic results and attempts to link microseismic source mechanisms to fracture behavior require an understanding of the geomechanics of the fracturing process. Stress calculations around fractures show that the area normal to the fracture surface is stabilized by a pressurized fracture as a result of increased total stress and decreased shear stress. In this area, microseisms can only occur if leakoff pressurizes natural fractures, bedding planes, or other weakness features, and source mechanisms are thus likely to show a volumetric component. Conversely, the tip tensile region is destabilized by a reduction in total stress and an increase in shear stress, with the likelihood that microseisms would be generated in this region because of these changes. Such microseisms would not yet be invaded by the fracturing fluid, and events that are mostly shear would be expected. Systems with multiple fractures, such as those that are potentially created in multiperforationcluster stages, are much more complex, but similar elements can be outlined for those as well.
Source mechanisms can help delineate these different types of microseismic behaviors, but evaluation of such mechanisms reveals that they provide no significant information about the hydraulic fracture. While it would be valuable if source mechanisms could provide information about the mechanics of the hydraulic fracture (opening, closing, proppant, etc.), calculations show that both the energy and volume associated with microseismicity are an insignificant fraction of the total energy and volume input into the stimulation. Thus, hydraulic fractures are almost entirely aseismic. Analysis of source mechanisms should be concentrated on what that data reveals about the reservoir (e.g., natural fractures, faults, etc.). Integrated diagnostic studies provide more value in understanding both the microseismicity and interpretation of the microseismic results.
Optimizing Perforating Charge Design for Stimulation
Authors: Quattlebaum Clinton C. , Borgen Ken , Xue Zhenyu , Wilkinson Pete 
Published: October 2012

Abstract
Hydraulic stimulation technologies, which are vital in maximizing the production of unconventional reservoirs, have typically focused on pumping capacities and rates, hydraulic fluid viscosities, and proppant materials. A technology that historically has been overlooked, but is critical to an efficient hydraulic stimulation, is the actual perforations through which the treatment is pumped.
Fundamental rock and fracture mechanics demonstrate that perforation shot density, phasing, and hole size affect breakdown and treating pressures and injection rates, and can be a cause of early screenout. Although some of these perforation parameters are considered in the best practices, perforation hole size is often misunderstood.
Complex computer fracture models, used to plan stimulation and completion programs, often incorporate average holediameter values with little consideration of the actual hole sizes or the variance from shot to shot. New research documents how this inconsistency can be considerable when using standard shaped-charge perforators. Nevertheless, perforating charges designed for natural completions, which focus primarily on the depth of penetration, are continuously used before hydraulic stimulation, ignoring the importance of consistent hole size. Advanced simulations using finite element analysis (FEA) have confirmed that fracture placement in a reservoir requiring stimulation would benefit significantly from maintaining consistency in the size of the perforation exit-hole.
This work reviews the analysis performed and the subsequent successful field results for a new class of shaped-charge. The new fracture charge is engineered to maximize hole-diameter while maintaining a consistent exit-hole diameter independent of well profile and/or gun eccentricity. Designed for perforating before a hydraulic stimulation, a fracture charge has been shown to optimize fracturing efficiency and placement by ensuring that each perforation tunnel contributes equally during the fracture treatment, which contributes to providing cost effective hydraulic stimulation and maximizing subsequent asset value.
Flow Rate Prediction in Multilateral Wells Using Distributed Temperature Sensors
Authors: Almulla J. M. , Yang C. , Zhu D. 
Published: October 2012

Abstract
The new advancements in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. The new challenge that we are facing today is to maximize the benefits of the large amount of data provided by these tools. One of these benefits is to utilize the continuous stream of data to determine the flow rate in real time of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. A theoretical model is developed to predict temperature and pressure in trilateral wells. The model is used as a forward engine in the study and an inversion procedure is then added to interpret the data to flow profiles. The forward model starts from a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the motherbore (main hole) and in the laterals. Then we use the inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that matches the temperature and pressure in the well is identified. The production distribution from each lateral is determined based on this approach.
Examples are presented in the paper. The value of the model approach for production optimization for trilateral wells is illustrated through parametric study.
An Automated Petrographic Image Analysis System: Capillary Pressure Curves Using Confocal Microscopy
Authors: Al Ibrahim M. A. , Hurley N. F. , Zhao W. , Acero-Allard D. 
Published: October 2012

Abstract
Laboratory mercury injection capillary pressure (MICP) analyses are key inputs into reservoir simulators. Although laboratory MICP measurements are accurate, they are slow, expensive, not friendly to the environment, destroy samples, and are not useful for pore-throats larger than 100 microns. This paper presents a fast and accurate automated petrographic image analysis system, used to compute pore-body and pore-throat size distributions and simulated capillary pressure curves. Input includes high-resolution petrographic images, such as those from confocal microscopy (0.25-microns resolution), and laboratory-derived porosity measurements. Our system can be used in conjunction with laboratory Special Core Analysis (SCAL) to obtain more accurate representations of reservoir properties.
To enable us to compute numerical SCAL measurements, we introduce the Expanding Flow Model (EFM) to show fluid-flow behavior inside pores. This model identifies the largest attached pore-throat as the throat that controls fluid flow in, or out, of a particular pore-body. Pore-throats are extracted using a novel image-analysis technique, based on watershedding algorithms and differences between processed images. We then compute: (a) pore-body and pore-throat size distributions, (b) numerical SCAL in the form of simulated capillary pressure curves for pore bodies and pore-throats, (c) representative element areas (REAs), which are the smallest areas that statistically capture heterogeneity, and (d) values that represent image quality to measure confidence in the results.
We have analyzed a number of samples with different porosity and permeability characteristics. Simulated capillary pressure results show a close match to laboratory data if good-quality representative images and accurate laboratory-derived porosity values are used. Rocks with lower porosity tend to produce better results. Simulated results match raw laboratory data, and eliminate closure-correction factors used in Thomeer capillary-pressure analyses.
A Completion Technology Milestone-The First 25,000 psi 500°F Packer Seal System
Authors: Doane James , Deng Guijun , Collins Scott 
Published: October 2012

Abstract
Increased energy demands for oil and gas have triggered the need to exploit high-pressure/high-temperature (HP/HT) fields, including extreme HP/HT and ultra HP/HT fields. However, well completion of ultra HP/HT fields is posing great technological challenges to operator and service companies. Existing completions technology seems to be reaching its design limits at around the 15,000 psi and 450°F territory.
As operators continue to drill into deeper and more extreme formations, the demand for technologies to suit these environments will steadily increase. Great efforts have been made to overcome the hurdles to develop safe and reliable completion tools qualified for conditions in excess of the 15,000 psi and 450°F territory across the industry over the years. A technological milestone was recently set in packer seal system development—the first 25,000-psi 500°F packer seal system.
Qualification testing was conducted with nitrogen to all the rating envelope points at 500°F with a cool down to 250°F.
The packer seal system passed all tests with no visible seal element extrusion, and no leaks were detected at any of the load points during testing.
This paper presents how this innovative seal system design evolved from several field-proven HP/HT seal systems, and how technological challenges are addressed by adopting state-of-the-art materials and design processes. The paper includes information about conceptual design, design optimization using finite element analysis (FEA), material characterization for both metallurgical and seal material, and seal assembly manufacturing. The qualification testing processes for this 25,000-psi 500°F packer seal system are also described, along with the market potential for these ultra-HP/HT wells.
Surveillance of Complex Displacement Mechanisms in Mature Reservoirs to Maximize Recovery
Authors: Zett Adrian , Webster Mike , Rose Hilary , Riley Steve , Trcka Darryl , Kadam Nilesh 
Published: October 2012

Abstract
The Columbus basin offshore Trinidad is a mature hydrocarbon province. It contains multiple, stacked, discrete reservoirs which are supported and driven by complex displacement mechanisms. The reservoir surveillance challenges in the basin are compounded by the interaction of low salinity formation water, multiple fluid phases, thin beds, and completions that present difficult conditions for cased hole reservoir monitoring instruments.
Challenging current monitoring practices resulted in the implementation of new strategic measurements in the surveillance plan that delivered valuable insights and clarity to complex reservoir management problems.
The results obtained using existing procedures and technologies highlighted their shortcomings and uncertainties. To address these issues emerging technologies were evaluated under these challenging conditions. The results obtained clearly prove that tangible benefits could be realized through the use of the new surveillance techniques.
The benefits of applying new technology as part of an integrated surveillance strategy will be described in this paper. This new approach has helped reduce the uncertainty in both fluid contact movement and remaining hydrocarbon saturations. This has had a direct impact on reservoir simulation and the definition of future reservoir targets.
ESP Technology Maturation: Subsea Boosting System With High GOR and Viscous Fluids
Authors: Barrios L. , Scott S. , Rivera R. , Sheth K. 
Published: October 2012

Abstract
This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting systems with high GOR and viscous fluids. It will focus on the developmental research on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes.
The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock conditions (Barrios 2010 [6]). The objective of this study is to predict the operational conditions that cause degradation and gas lock. This paper provides a summary on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR fields to in support of Shell's BC-10 developments. These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment. This paper will describe the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875 series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixed-type pump.
Extensive testing and qualification of the subsea boosting system was undertaken prior to field considerations. Testing was conducted at the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for Shell's deepwater assets. This paper describes the subsea boosting system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on ESPs. The test facility work was performed using pumps with ten or more stages moving fluids with viscosity from 2 to 400 cP at various speed, intake pressure, and gas void fractions (GVF, aka gas volume fractions). The testing at Shell's Gasmer facility revealed that the MVP-ESP system is robust and performance tracked theoretical predictions over a wide range of two-phase flow rates and light-viscosity oils
Accurate Microseismic Event Location Inversion Using a Gradient-Based Method
Authors: Li Gaoming , Chen Jingyi , Han Mei , Gajraj Allyson , Xing Yang , Wu Furong , Liu Hong , Yin Chen 
Published: October 2012

Abstract
From the microseismic data collected during multi-stage hydraulic fracturing, we may pick out the first arrival times for both P- and S-waves for each event and at each geophone. With triaxial geophones, the azimuths of the events may be derived from the hodograms. The P- and S-wave arrival times contain the distance information from the event location to the geophones as well as the event initiating time. The azimuth from hodograms gives the orientation information of the event locations. Inverting these interpreted microseismic data yields the event location parameters, which can be used to characterize the hydraulic fractures for reservoir modeling. This paper presents an efficient gradient-based microseismic event location inversion method. The forward model that is used to calculate the first arrival times is the finite-difference solution of the Eikonal equation. A novel method is devised to obtain the gradient of the first arrival times to the event location parameters in addition to the first arrival times in one forward model run. The method is applied to a realistic multilayer shale gas reservoir with a horizontal well and several stages of hydraulic fractures. The results show that the first arrival times obtained from the surface geophones yield better event location parameter estimation assuming we can pick up the events from the surface geophone signal. When the geophones are placed downhole in nearby wells, the inverted event locations are less accurate than the ones with surface geophones but can have a relative good characterization fo the fracture propagation.
Advanced Wireline Formation Tester Applications in Challenging Rocks and Environments
Authors: Omokaro Felix , Musharfi Nedhal , Zeybek Murat 
Published: October 2012

Abstract
Carbonate formations are highly heterogeneous with variations from grainstones to mudstones. Digenesis leads to changes of the rock's original nature, like dolomitization, vugs, layering and fracturing. These variations have effects on rock quality in terms of porosity and permeability. Similarly, clastics, including shaly sands, can be quite challenging in terms of accurate formation evaluation.
Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) greatly aids reservoir description. Standard formation evaluation tools and techniques sometimes result in low level of confidence in identifying and quantifying the presence of hydrocarbon in certain reservoirs. The application of modern wireline formation testers has become a useful tool in minimizing uncertainties in situations where we have low confidence in log evaluation. Some borehole conditions and reservoir architectures, like fractures, vugs, and low mobility and mud losses could also pose some challenges while performing formation testing.
In this paper, several examples and case histories of the application of advanced wireline formation testers across varieties of rocks with fractures, vugs and different borehole conditions are presented. Results indicate that reservoir heterogeneities can be described and quantified more accurately with the integration of dynamic data to aid reservoir characterization. This paper also demonstrates how to handle the challenges of detecting the early traces of hydrocarbon arrival for real time decisions during pressure testing and sampling.
Engineering Analysis of Hand Union Connections in Coiled Tubing Operations
Authors: Barraez R. , Yeung T. 
Published: October 2012

Abstract
In an effort to enhance well intervention efficiency while still ensuring safe operations, the mechanical implications of using a quick connect hand union between the wellhead and the coiled tubing blowout preventer to reduce rig-in and rig-out time during coiled tubing operations were explored. The study was conducted in order to support an application to the local regulatory body, requesting that an exemption to standard operating regulations be granted for the proposed procedure.
To complete the study, the locations where maximum tension and compression forces exist during a typical coiled tubing operation were identified. Finite element analysis was then used to simulate and compare the stress distribution in both hand union and flanged type connections. Load cases were based on conditions typically seen during coiled tubing operations.
This paper presents the results of the study. The areas of maximum stress and the calculated safety factor based on the material yield strength of both the hand union and flanged connections for every scenario under given loading conditions are shown. The paper also outlines how the engineering analysis defined the loading limitations in order to safely incorporate the hand union connection as part of the rig-up procedure for coiled tubing operations.