bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Method To Model Relative Permeability in Compositional Simulators To Avoid Discontinuous Changes Caused by Phase-Identification Problems
Authors: Yuan Chengwu , Pope Gary A. 
Published: November 2012

Summary
Simple methods, such as the use of density during compositional simulations, often fail to identify the phases correctly, and this can cause discontinuities in the computed relative permeability values. The results are then physically incorrect. Furthermore, numerical simulators often slow down or even stop because of discontinuities. There are many important applications in which the phase behavior can be single phase, gas/liquid, liquid/liquid, gas/ liquid/liquid, or gas/liquid/solid at different times in different gridblocks. Assigning physically correct phase identities during a compositional simulation turns out to be a difficult problem that has resisted a general solution for decades. We know that the intensive thermodynamic properties, such as molar Gibbs free energy, must be continuous, assuming local equilibrium, but this condition is difficult to impose in numerical simulators because of the discrete nature of the calculations. An alternative approach is to develop a relative permeability model that is continuous and independent of the phase numbers assigned by the flash calculation. Relative permeability is a function of saturation, but also composition, because composition affects the phase distribution in the pores (i.e., the wettability). The equilibrium distribution of fluids in pores corresponds to the minimum in the Gibbs free energy for the entire fluid/rock system, including interfaces. In general, however, this relationship is difficult to model from first principles. What we can easily do is calculate the molar Gibbs free energy (G) of each phase at reference compositions where the relative permeabilities are known or assumed to be known and then interpolate between these values by use of the G calculated during each timestep of the simulation. Relative permeability values calculated this way are unconditionally continuous for all possible phase-behavior changes, including even critical points. We tested the new relative permeability model on a variety of extremely difficult simulation problems with up to four phases, and it has not failed yet. We illustrate several of these applications.
Improving Real-Time Image-Data Quality With A Telemetry Model
Authors: Hartmann Andreas , Akimov Oleg , Fulda Christian , Morris Stephen 
Published: November 2012

Summary
The introduction of new measurements constantly increases the amount of real-time data from logging-while-drilling (LWD) services, providing better information for informed decision making. This is matched by telemetry technologies that provide data rates from bits per second to megabits per second. During a deployment, the bandwidth is shared between several services requiring different data rates, leaving the user with the task of aligning telemetry technology and shared data rates to the application. High-volume services often allow for data compression. Lossless or near-lossless compression provides the best data quality but requires large bandwidth. Lossy compression reduces bandwidth usage dramatically, but may result in degraded data quality. Thus, telemetry planning must be tied closely to service objectives and requires expert advice.
We present a planning approach in which we model the realtime-data compression of an LWD high-resolution imaging tool that uses a flexible compression algorithm. This system allows lossy compression for telemetry rates as low as 1 bps, while at the same time delivering memory-data quality using high-speed-telemetry technology. The compression rate determines the image resolution and must be adjusted to the detail required in the transmitted image. Using offset-well data or simulated memory data, the expected real-time image is simulated and its level of detail quantified. For instance, the presence and appearance of fractures in real time can be forecasted. This enables us to optimize telemetry usage and define compression and drilling parameters for a successful deployment of the imaging service.
This paper will outline the methods and benchmark the technology of the imaging tool, using real-time data measured during field deployments. We will then use parameter variations to show how increasing net bandwidth improves the amount of detail in the images, and how these are used for different levels of realtime-data interpretation.
In-Situ Mechanical- and Functional-Behavior Characterization of a Shape-Memory Polymer for Sand-Control Applications
Authors: Yuan Yusheng , Goodson Jim , Johnson Mike , Gerrard David 
Published: November 2012

Summary
Pumping a gravel slurry between a downhole screen and the rock matrix has been used to prevent production of undesirable solids or sand from the formation in traditional oil and gas completions. Recently developed expandable technology attempts to eliminate this operation by expanding metallic sand-control screens against the wellbore. However, one problem with this process is borehole irregularity. It is desirable to have a smart downhole-screen structure that is capable of self-expanding and conforming to the borehole surfaces in certain downhole conditions. Use of an advanced shape-memory-polymer (SMP) structure offers breakthrough performance for sand-control applications. Proper characterization and full understanding of the thermal, mechanical and functional behavior of the SMP structure in simulated downhole pressure, temperature, and fluid conditions are critical for successful applications.
This study used a high-pressure/high-temperature (HP/HT) in-situ mechanical test system and test method to characterize the in-situ hot-wet mechanical and functional behavior of the SMP foam, including deployment and contact-pressure-development functional properties, compressive resistance, and time-dependent stress-relaxation and creep mechanical properties. These properties were determined during immersion in a fluid environment at various temperatures under ambient pressure and 3,000- to 5,000-psi hydrostatic pressure. Effects of the test temperature, fluid condition, and the hydrostatic pressure on mechanical and functional properties of the SMP foam were identified. Study results were used to establish the operational window of the SMP screen as a sand-control solution.
Alkaline Steam Foam: Concepts and Experimental Results
Authors: Lau H.C.. C. 
Published: November 2012

Summary
Experimental studies have shown that the steam-foam process can be enhanced significantly by injecting a suitably formulated alkali/surfactant mixture in the aqueous phase of steam. Emulsionscreening tests, corefloods, and flow-visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16–18 carbon, Na2CO3, and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced-oil-recovery (EOR) processes.
First, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Second, by precipitating divalent ions that get ion exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Third, a suitably formulated alkali/surfactant system reduces the oil/water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than the oil alone and can be readily transported. Consequently, the residual-oil saturation (ROS) is reduced to a value less than that of steam. Fourth, this lower ROS reduces the destabilizing effect of oil on foam, resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifth, the reduction in gravity override also reduces loss of heat to the cap rock, thereby improving steam utilization.
When applied to steamdrive, alkaline steam foam has the benefit of increasing foam-propagation rate, improving mobility control, improving steam use, and reducing the ROS. Potential applications of alkaline steam foam to steam soaks and steam-assisted gravity drainage (SAGD) are also discussed.
Estimating Drainage-Area Pressure With Flow-After-Flow Testing
Authors: Kabir C.S.. S. , Elgmati M.. , Reza Z.. 
Published: November 2012

SummaryEstimating the average drainage-area pressure (pav) of individual wells is a cornerstone to any reservoir-management practice. Yet conventional methods do not always offer reliable solutions to this vexing problem. This study shows that transient flow-after-flow (FAF) testing offers an excellent opportunity to establish pav in a time-lapse mode, when conducted following operational shutdowns. Instrumented wells are natural candidates for FAF testing.Real-time surveillance offers the opportunity to perform rate-transient analysis that results in drainage volume and, consequently, pav. However, gathering quality rate data commensurate with pressure over a long producing period is fraught with uncertainty, which raises questions about the validity of the pav so obtained. In addition, continuous changes in drainage-boundary conditions pose modeling challenges with a given reservoir model. Therefore, the independent estimation of pav cannot be overemphasized. This paper presents a theroretical framework for transient FAF testing and also shows a pragmatic approach to handling pressure/rate data incoherence.
Removal of Cyclic Borehole Noise From Low- and High-Resolution LWD Images and Its Impact on Image Interpretation
Authors: Sugiura J.. , Lee R.. 
Published: November 2012

Summary
The use of logging-while-drilling (LWD) imaging tools in realtime decision making and post-drilling analysis has become commonplace. However, image noise and processing errors because of inherent measurement physics can propagate errors and, thus, complicate interpretation of openhole log data and images. For example, standard density images tend to amplify image noise from small borehole irregularities. Among different borehole irregularities, spiraling is known to occur more frequently with conventional rotary assemblies, steerable motor assemblies, and rotary-steerable assemblies. When the cyclic-noise amplitude from spiraling becomes large relative to the measurement of the primary interest, it grossly affects the quality of the recorded formation bulk density, photoelectric factor, and neutron porosity.
This paper shows novel methods to remove cyclic noise from formation-evaluation (FE) images by applying frequency-domain filtering. Although the initial attempt of fast Fourier transforms (Zhang et al. 2010) illustrates the straightforward concept, it is seldom used because of implementation issues requiring interactive filter design and intensive operator intervention. Recently, a new method (Sugiura et al. 2011) has been designed to improve the filtering process. Additionally, the new adaptive filter designs automate the cyclic-noise-removal process from the FE images. Standalone software has been developed to process the entire image logs from one well, without human supervision. The software adaptively modifies the filter behavior as borehole-oscillation noise characteristics change with formation, drilling assemblies, hole inclination, and depth.
To examine its validity qualitatively, the algorithm is then applied to various field data, not only on low-resolution density images but also on higher-resolution density images. The new algorithm has been proved by bringing considerable improvement to the image quality without any artificial interruptions. The rugosity effect is reduced significantly, and the apparent resolution of bed-boundary features is increased.
Furthermore, comparative field examples illustrate the improvement in image-feature extraction. The method described here is critical, for example, for small-fracture detection and more-precise definition of formation-property contrasts indicative of bed boundaries in irregular boreholes. This new method not only is effectively used for density images but also is applicable to any other borehole images, such as resistivity and ultrasonic images.
Gas Permeability of Shale
Authors: Sakhaee-Pour A.. , Bryant Steven L. 
Published: November 2012

Summary
Permeability is one of the most fundamental properties of any reservoir rock required for modeling hydrocarbon production. However, shale permeability has not yet been understood fully because of the complexities involved in modeling flow through nanoscale throats. In this paper, we analyze the effects of adsorbed layers of methane (CH4) and of gas slippage at pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on scanning elecron microscope (SEM) images and a drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined on the basis of the Knudsen number (Kn) criterion (Knudsen 1909). The combined effects of adsorption and slip depend strongly on pressure and on conduit diameter. The results indicate that laboratory measurements made with N2 at ambient temperature and 5-MPa pressure, which is typical for a transient pulse-decay (TPD) method, overestimate the gas permeability at early life of production by a factor of four. This ratio increases if the measurement is run at ambient condition because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in the production rate of shale-gas wells. Laboratory data available in the literature for CH4 permeability at pressures below 7 MPa agree with model predictions of the effect of pressure.
New and Improved Methods for Performing Rate-Transient Analysis of Shale Gas Reservoirs
Authors: Nobakht Morteza , Clarkson C.R.. R. , Kaviani D.. 
Published: November 2012

Summary
Multifractured horizontal wells are currently the most popular method for exploiting low-permeability tight and shale gas reservoirs. Production data analysis is the most widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning (Ambrose et al. 2011). However, as pointed out by Clarkson et al. (2012), a fundamental problem with the application of conventional production data analysis to ultralow permeability reservoirs is that current methods were derived with the assumption that flow can be described with Darcy's law. This assumption may not be valid for tight/shale gas reservoirs, as they contain a wide distribution of pore sizes, including in some cases nanopores (Loucks et al. 2009). Therefore, the mean-free path of gas molecules may be comparable to or larger than the average effective rock pore throat radius, causing the gas molecules to slip along pore surfaces. This results in slippage non-Darcy flow, which is not accounted for in conventional production data analysis.
Clarkson et al. (2012) modified the pseudovariables used for analyzing gas reservoirs in production data analysis to account for slippage. They demonstrated that if the effect of slippage is not considered, it leads to noticeable errors in reservoir characterization. Clarkson et al. (2012) also mentioned that even after using the modified pseudovariables, the values for permeability and fracture half-length do not exactly match the input data to simulation. In this paper, a methodology to properly analyze the production data from a fractured well in a tight/shale gas reservoir producing under a constant flowing pressure in the presence of desorption and slippage is presented. This method uses a new pseudotime definition instead of the conventional pseudotime currently being used in production data analysis. The method is validated using a number of numerically simulated cases. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length or contacted matrix surface area, if permeability is known.
An Innovative Approach for Pore Pressure Prediction and Drilling Optimization in an Abnormally Subpressured Basin
Authors: Contreras Oscar , Hareland Geir , Aguilera Roberto 
Published: November 2012

SummaryThus far, an indirect generalized method to predict pore pressure under subpressured conditions has not been reported in the literature. In this work, an innovative procedure is presented for estimation of pore pressure and optimization of wells drilled in the abnormally subpressured Deep Basin of the Western Canada Sedimentary Basin (WCSB). The procedure starts with detailed evaluation of five wells drilled in a township that covers the study area. Pore pressure was calculated from sonic logs and the modified D exponent by the use of Eaton's method (Eaton 1975), which proved to be the most effective approach for abnormally subpressured conditions over a variety of methods tested (Contreras et al. 2011). The optimization procedure was carried out by use of the apparent-rock-strength log (ARSL), which is an effective indicator of formation drillability and is very sensitive to the pore pressure. Next, optimization of individual sections in each well was carried out to determine the optimum types of bits and operational parameters for the lowest cost of drilling.An artificial-intelligence function was implemented to set up the optimum combination of parameters in such a way that the rate of penetration (ROP) (m/h) was increased after a number of simulation runs while controlling the bit wear. Special attention was focused on tight gas reservoirs for selection of the most suitable parameters that increase the quality of drill cuttings. It was concluded that the roller-cone bit IADC 547 (with at least 0.73 hp in the bit per square inch) provides the best-quality cuttings for the Nikanassin Group. This is of paramount importance for increasing accuracy in the quantitative determination of permeability and porosity from cuttings particularly in those tight gas reservoirs where the amount of cores is very limited.It is concluded that wells in the Deep Basin of the WCSB can be drilled efficiently with seven bit runs while maintaining the cuttings quality, bit-wear level, and well stability at a significantly high average ROP of 13 m/h. Another conclusion is that the normal trend methods from sonic logs are the most effective approach when dealing with an abnormally subpressured basin.
Finite Horizontal Well Crossing a Natural Fracture Normally
Authors: Prats Michael , Raghavan R.. 
Published: November 2012

Summary
An analytic solution in terms of the Laplace transformation is presented to calculate the pressure distribution in multizone, composite reservoirs intercepted by a finite horizontal well that is oriented normal to the plane interfaces in an infinite field. A three-zone reservoir is analyzed for illustrative purposes, with the horizontal well traversing a thin high-permeability central zone confined between two parallel planes representing the natural fracture, and with the well completed in the adjacent zones. The method provides the transient pressure field for each of the three zones, allowing analyses of the flow fields both within the fracture and within the reservoir as a function of pertinent parameters. The computational scheme considered is both viable and robust. To our knowledge, this topic is yet to be analyzed in this fashion analytically.
The numerical results presented are limited to a parametric study of (1) transient well pressures and their time derivative and (2) steady-state flux and flow-rate distributions at the fracture faces as a function of distance from the well. A steady-state correlation of the productivity index is also provided.
We discovered that of the two generally accepted procedures for estimating the average well pressure, the one based on well rates proportional to the local permeability and well length gives results consistent with our model, whereas the one requiring equal average pressure at each well segment introduces significant disturbances to the flow field near the fracture-well intercepts, at least when small and large well lengths are present, as is the case in the problem under consideration. This subject needs additional investigation.
3D Inversion-Based Interpretation of Marine CSEM Data
Authors: Zach J.J.. J. , Frenkel M.A.. A. 
Published: November 2012

SummaryThe marine controlled-source electromagnetic (CSEM) method has been evolving into a geophysical imaging tool for increasingly complex geological settings in which multiple resistive bodies can be resolved. An advanced subsurface imaging workflow for 3D CSEM surveys is presented, which reproduces the resistivity distribution to within a spatial resolution determined by the frequencies included. The performance of our advanced-processing workflow is demonstrated using a case study from the Gulf of Mexico (GOM), where a dense 3D grid was acquired over an area of high-quality seismic data and well log control.At the core of our 3D workflow is an inversion methodology with approximate Hessian-based optimization and a fast finite-difference time-domain forward operator. The optimization matches the synthetic to the measured field within 100–200 iterations and is sufficiently robust in three dimensions to avoid expensive regularization schemes. The sensitivity of the gradient-based inversion to the starting model is addressed by investing considerable effort in building 1D inversion-based starting models. At the same time, 3D inversion algorithms for survey layouts, including azimuthal data, demand high-quality data conditioning for which we present a processing sequence from time-domain electromagnetic data acquired by seabed receivers to frequency-domain data and weights for inversion.Detection and delineation of reservoirs in the presence of salt is recognized as a major challenge to CSEM methods. In order to interpret 3D data accurately in such a complex environment, the true-resistivity cube is built from a sequence of constrained inversion-based interpretation steps. Using a data set acquired in 2008 in the GOM, we demonstrate the ability of our 3D technology to resolve small (2×2 km), low-resistivity pay (Δρ:5Ω·m) targets within the vicinity (&lt; 1 km) of large salt bodies. In this case study, the 3D method converged within 1 week, running on 150 parallel nodes.