bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Fracture Mapping from the "Live" Treatment Well
Authors: Wright C. A. , Davis E. J. , Ward J. F. , Griffin L. G. , Fisher M. K. , Lehman L. V. , Fulton D. D. , Podowski J. , Grieser W. V. , Special J. F. 
Published: December 2007

Abstract
The recent and dramatic increase in direct fracture mapping has profoundly altered our understanding of how fractures really do grow. New fracture-mapping technologies have allowed us to often directly measure what we could previously only model or assume. However, perhaps the greatest limitation of these new direct fracture-mapping technologies (tilt and microseismic) is the need for a nearby offset well in which to deploy instruments. In many environments, most notably offshore, there is often no feasible way to employ an offset observation well. Treatment well tilt mapping uses the fracture (injection) well itself as the "observation" well. The goal, quite simply, is to expand the range of environments where direct fracture mapping can be performed.
The concept is simple: if fracture-induced deformation can be measured thousands of feet away at the surface or in offset wells, then it most certainly can be measured in the fracture well itself. The measurement of fracture-induced tilt versus time and depth (via an array of 4 to 20 tiltmeters) can allow robust real-time mapping of fracture height and width. Fracture length is then "modeled" based on observed height and width, and inferred fracture fluid efficiency. Treatment well tilt measurements can also provide direct measurement of mechanical fracture closure aiding, among other things, the estimation of formation closure stress.
Mapping from the treatment well brings its own set of limitations and challenges. One is conducting minute wellbore movement measurements in the midst of a highvelocity flow stream. We have solved this challenge. Field data shows that the fracture-induced tilt signals in the treatment well are several orders of magnitude higher than those measured in offset wells, and they are much greater than the fluid-motion noise. The trickier challenge is deploying tools in a well during the pumping of proppant. So far we have performed real-time treatment well mapping only on fractures with clean fluid (i.e., no proppant), however, efforts are underway to overcome the difficulties with proppant. This paper provides an overview of the basic concepts, shows some real-data from treatment well applications, and presents one brief case study.
Proper Use of Proppant Slugs and Viscous Gel Slugs can Improve Proppant Placement During Hydraulic Fracturing Applications
Authors: McDaniel B. W. , McMechan D. E. , Stegent N. A. 
Published: December 2007

Abstract
When using hydraulic fracturing techniques to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. Many times, these problems are specifically related to the perforation entry or to the width of the fracture near the wellbore. A likely conclusion is that insufficient width generation in the NWB region is the result of a tortuous (rapidly turning or twisted) path for the first few inches or feet of the fracture. Within this near-wellbore region, such fractures must overcome rock stresses greater than the least principle stress. In other instances, the inadequate width problem may result from the generation of a large number of independent near-wellbore fracture planes (starter fractures) instead of only one fracture (or at least only a few). Additionally, the hydraulic fracture may initiate from a fluid-filled microannulus rather than the perforations, which can lead to significant proppant-pumping limitations.
During the early 1990's, the oil industry began to consider these NWB problems more seriously. Procedures to help identify the problems were developed, and techniques involving proppant slugs and viscous gel slugs were used to mitigate such problems before or during a fracture-stimulation treatment. Alterations of the well completion plan proved to be a major part of successfully reducing the occurrence of similar problems in future wells in that reservoir. This paper discusses this technology and its evolution through recent years, as well as current applications of these techniques.
Experience in Acid Diversion in High Permeability Deep Water Formations Using Visco-Elastic-Surfactant
Authors: Chang F. F. , Acock A. M. , Geoghagan A. , Huckabee P. T. 
Published: December 2007

Abstract
It is a great challenge to divert acid into untreated zones in a thick, heterogeneous, and high permeability sandstone formation. The heterogeneity can be created by hydraulic fracturing, acidizing, or the nature of the reservoir. Common diverting agents do not work well in these situations. In high permeability porous media, foam has the tendency to segregate, gaseous phase will occupy smaller pores while the aqueous phase occupies the larger pores1. Due to the relative permeability effect, the higher permeability streaks becomes the preferable path for acid treatment fluids2. Therefore, limited effective diversion can be achieved by foam. Other diverting agents rely on particulate matter or polymer solution to plug off thief zones temporarily. However, the invasion of the undissolved particles and polymer residue can cause further formation damage.
Owing to its rheological properties, and its lack of solids, Visco-Elastic-Surfactant diverting agents (VESDA) have been proven to be effective for acid diversion in carbonate formations3, where large flow channels are generated due to acid-rock reaction. This current study extends the application into diversion in high permeability, highly heterogeneous sandstone formations. Throughout this paper, the term VESDA is used to refer to the VES diverting agent. Laboratory tests have shown that VES is capable of increasing the flow resistance in the high permeability rock (simulated by a proppant pack) and will divert treatment fluid into the low permeability sandstone matrix. The process was more efficient if multiple stages of alternating VES and acid were used. Field case histories in Gulf of Mexico are also presented in this study to demonstrate the effectiveness of the VES material for acid diversion in the highly permeable and heterogeneous sandstone reservoirs.
Effect of Resistive Invasion on Resistivity Logs
Authors: Crary Steve , Jacobsen Scott , Rasmus John C. , Spaeth Rob 
Published: December 2007

Abstract
One of the more difficult decisions facing the petrophysicist is deciding which resistivity tool to use. Induction tools are best suited for low-resistivity formations drilled with fresh or nonconductive mud. Laterolog or resistivity tools are best in the opposite conditions. An important effect to consider when choosing the tool is the contrast of flushed zone resistivity (Rxo) to true formation resistivity (Rt). Laterolog tools have a difficult time estimating true formation resistivity when Rxo is greater than Rt. This effect, though well known, still seems to catch petrophysicists by surprise and can cause serious errors in the formation analysis. In this paper we demonstrate the potential problems by examining three case studies where both induction and laterolog tools were run. Comparing measured tool response to forward modeling results helps explain the measurements.
The first case study could be considered a classic case of resistive invasion. The mud resistivity was 0.78 ohm-m at bottom hole temperature. In a wet sand, the deep laterolog resistivity measurement is affected by the higher flushed zone resistivity and consequently reads much higher than the deep induction measurement. The resistive invasion is clearly seen on either the laterolog resistivity or induction measurements and can therefore be detected, although it is easier to estimate Rt with the induction. Resistive invasion effects are much more difficult to see on our second case study. A fractured carbonate with high formation resistivity of around 100 ohm-m was drilled with fresh mud. The fresh mud invasion in a wet zone results in Rxo greater than Rt, and the deep laterolog resistivity was consequently higher than the deep induction by almost one decade. However, the natural fractures resulted in the deep laterolog resistivity reading being greater than the shallow resistivity, which is typical of pay zones, and made detection of the shallow resistive invasion difficult using only a deep and shallow laterolog resistivity. Forward modeling suggests that the deep induction provides the best estimate of Rt in wet zones, while the deep laterolog resistivity measurement is best in hydrocarbon intervals. The final case study demonstrates this effect on a laterolog resistivity measurement made while drilling. The measurement was to be used to stop drilling at the top of a water leg. Unfortunately, the fresh mud filtrate and rapid mud spurt losses resulted in a flushed zone resistivity higher than formation resistivity in the water leg. Comparison between the laterolog bit resistivity (earliest measurement on the tool) and later measurements provided an indication of the effect. However, the difference is subtle and difficult to see on the field logs. Comparisons with the induction data clearly demonstrate the effects of resistive invasion on laterolog measurement in this environment.
New Processing Techniques to Meet Challenges of LWD Acoustic Logging
Authors: Market Jennifer , Barnett Craig , Deady Ron , Althoff Gary , Varsamis Georgios L. , Blanch Joakim 
Published: December 2007

Abstract
LWD acoustic logging presents several challenges beyond those faced in wireline logging: the LWD environment is inherently noisier, the drill collar supports additional propagation modes, the data are obtained at irregular depth intervals, and tool centralization is generally poor. Furthermore, it is difficult to achieve a pure monopole or pure dipole transmitter mode in LWD tool configurations; this complicates slow shear measurements based on flexural or Stoneley interface modes. These factors often result in a greater number of coherent arrivals being detected at the receiver arrays, and prohibits the effective use of some conventional techniques such as data stacking and dipole receiver subtraction, raising the challenge of properly identifying the various coherent modes of interest in determining formation compressional and shear velocities.
To address the added complications of LWD sonic logging, new processing and analysis techniques have been developed for use with a second-generation LWD sonic tool. In addition to the standard slowness vs. arrival time coherence computation, the frequency, energy, delay, and attenuation of each coherent arrival is also computed. These properties can be examined at each acquisition to determine the properties of the desired compressional, refracted shear, and interface modes. A new and innovative graphical user interface then allows the processing analyst to employ all of the relevant properties of the various coherent arrivals when producing the final compressional and shear slowness logs.
Field examples from various formation and borehole environments illustrate the application of the multi-parameter analysis approach to LWD sonic log processing. Examples include the identification and elimination of various types of residual tool modes and spatial aliasing. Examples are drawn from both fast and slow formations.
Advanced Forward Modeling Helps Planning and Interpreting NMR Logs
Authors: Bonnie Ron J. M. , Marschall Dave M. , Fam Maged Y. , Siess Charles P. 
Published: December 2007

Abstract
Nuclear Magnetic Resonance (NMR) logging has gained its position in the industry as stand-alone interpretation or as an additional source of information to conventional log data. There are a wide variety of examples where NMR logging has disclosed secrets of the well that were not discovered by conventional logs, e.g. low resistivity pay zones identified by NMR logs but completely overlooked or viewed as not economically viable by conventional log interpretation. In some complex environments, NMR logging may even be the only alternative available to assess critical formation parameters.
The interplay of rock and fluid properties, reservoir parameters, and NMR tool characteristics and settings shape the recorded NMR signals. Pre-job planning is critical for the success of the logging run especially now that NMR technology has gained more general acceptance and is being applied in complex environments. Integration of known parameters and estimated in situ properties may reduce the acquisition time, demonstrate the feasibility of a proposed logging run, and provide a handle to optimize the acquisition cycle. A priori knowledge will ultimately lead to better data and results in less time.
We have built a state of the art, multi-fluid, forward model to simulate NMR responses under given conditions. The latest understanding of NMR physics is incorporated in the model, including free and restricted diffusion. The model is a versatile planning tool, linked to a very user-friendly graphical user interface, which offers easy input and great flexibility.
Specifics of all currently available MRIL® tools and a broad range of rock and fluid properties are directly accessible through embedded database files. The user, however, has the flexibility to alter these values or to incorporate specific, regional knowledge. Polarization curves, composite transverse relaxation time (T2) spectra, and differential spectra are displayed. Computed fluid volumes, saturation levels, and relevant, mean T2 values are tabulated. The Planner is also being used more and more as an interpretation aid: geologists and petroleum engineers are testing their hypotheses by comparing computed NMR signals to actual logging data.
Permeability and Anisotropy Determination in a Retrograde Gas Field to Assess Horizontal Well Performance
Authors: Ayan Cosan , Donovan Michael , Pitts Alan S. 
Published: December 2007

Abstract
Uncertainty in permeability anisotropy proved to be one of the key factors while evaluating the performance of horizontal/deviated wells in the field under study. This gas condensate field, located in the UKCS of the North Sea, has sands of varying quality. All wells are producing below the dew point with a liquid condensate bank developing early in the life of the well, affecting productivity. Drilling horizontal and highly deviated wells to increase PI was considered a viable approach. However, the performance of such wells depends highly on permeability anisotropy; data was scarce and available only from core, limiting the scale of investigation.
This paper describes the investigation of permeability anisotropy in selected layers in the reservoir. Open hole vertical interference tests were conducted at five reservoir zones with a wireline formation tester using multiple probes.
The tests were analyzed using an analytical model, which simulates the pressure response at an observation probe vertically displaced from the active probe. Four tests showed a clear response where horizontal and vertical permeabilities were computed. The favorable anisotropy figures obtained from analyzing the Modular Formation Dynamics Tester (MDT)† data gave increased confidence about associated PI improvements from highly deviated wells. With this information, highly deviated wells were incorporated within the near term drilling program.
How Should We Measure Residual-Oil Saturation?
Authors: Wyman R.E. 
Published: December 2007

1978 Rocky Mountain Regional Cody Wyoming May 17–19, 1978

Abstract;
A review of the advantages and limitations of methods to measure residual oil show that reasonable accuracy can be obtained from both open hole and cased hole techniques. Especially accurate methods for open hole include the nuclear magnetism log-inject-log technique and the pressure core barrel. In cased hole the pulsed neutron log-inject-log technique and the backflow tracer has been successfully tested. Other ideas of how to measure residual oil include use of reservoir performance, conventional cores, resistivity logs, carbon-oxygen logs, gamma radiation logs and dielectric logs.
Super-Critical Rate Based on Economic Recovery in Water and Gas Coning by using Vertical and Horizontal Well Performance
Authors: Recham R. 
Published: December 2007

Abstract
The purpose of this work is to develop a new method suitable for hand calculation. Simulation is shown to be a cumbersome process to investigate and predict optimum oil rate based on maximizing economic recovery, and breakthrough time for both vertical and horizontal wells.
Since the early days, several experiments and mathematical analyses were conducted to solve coning problems, since the production of water and gas increase the cost of producing operations, reduce the efficiency of the depletion mechanism, and the overall recovery. One of the basic conclusions of many analyses was if oil is produced at a sufficiently low rate, coning of water and gas can be avoided, and only oil is produced. This low rate is called critical oil rate.
These different theoretical correlations are conflicting and give different answers, probably due to the different assumptions each of them involves, and many times the critical rates are too low, and for economic reasons, a well is frequently produced in field operations at a rate above critical rate. This results in production of water, gas as well as oil, which could results in a low economic recovery.
To overcome this problem, an extensive parametric sensitivity analysis of the various reservoir and fluid properties on water and gas coning was investigated and performed using numerical simulation to provide input data for developing a new predictive correlation needed to calculate breakthrough time and optimum oil rate based on maximizing economic recovery for both vertical and horizontal wells. The parameters were grouped based on the regression analysis.
The new method is more robust, where the developed empirical correlations were tested and found to be reliable and closely accurate in estimating optimum oil rate to be used for a well in field operations. These correlations are illustrated with several field examples from Hassi R’mel field, Algeria, where calculated and observed, show satisfactory agreement of correlations with production data.
Efficient 2-Phase Upscaling in 2D
Authors: Virnovsky G. A. , Lohne A. 
Published: December 2007

Abstract
In heterogeneous reservoir containing 2 liquid phases, e.g., oil and water, the flow rate in combination with small to medium scale heterogeneities in both absolute permeability and capillarity defines dynamic capillary entrapment of oil and water. Since those effects involving both viscous and capillary forces happen on the lengths of cm to meters scale a simulator can only capture them if the grid is sufficiently refined. With typical size of the reservoir model grid blocks of the order of 100m in horizontal directions, and of the order of meters in the vertical direction, the small-scale heterogeneities have to be accounted for through the so-called effective absolute and relative permeabilities.
Generally, the effective relative permeabilities are rate-dependent[17],[13],[8],[3]. We have developed a software package which computes the effective absolute and also relative permeabilities in 2D in 2 "easy" cases, at capillary limit (which is also called capillary-gravity equilibrium), i.e., at low rate, and at viscous limit, i.e. high rate limit. Both ensuing effective properties, the absolute and the relative permeabilities, are generally full tensors. The computational procedure includes numerical finite difference solution of the elliptic equation with periodic or classic boundary conditions.
We present solutions of the problem for a number of simple heterogeneities and compare it with solutions obtained by other numerical and analytical procedures including the so-called self-consistent approach. The comparison reveals quantitative estimates of the accuracy and the computational efficiency of the developed software. In addition, a number of realistic heterogeneities are considered when only numerical upscaling is feasible.
Viscous-Elastic Fluids Can Mobilize Oil Remaining after Water-Flood by Force Parallel to the Oil-Water Interface
Authors: Wang Demin , Cheng Jiecheng , Xia Huifen , Li Qun , Shi Jingping 
Published: December 2007

Abstract
Residual oil after water flooding appears in three types: oil drops, films and clusters. Work performed using Newtonian fluids shows that to mobilize the residual oil remaining after water flooding, the driving forces, on condition of oil-water IFT (interfacial tension) being constant, need to be increased by one thousand to ten thousand times over that of water-flooding before the capillary forces retaining the residual oil can be overcome[1]. Viscous forces cannot be increased by such a large magnitude in the field.
Polyacrylamide (PAM) solutions have little effect on the oil-water IFT. However, results in the laboratory and field show that after flooding by polymer fluids, all types of microscopic scale residual oil in porous media are lowered[2]. The amount that is lowered is related to the elasticity of the fluids. Other conditions being the same, the higher the elasticity, the lower the residual oil saturation.
The results of lab tests (including microscopic visualization cores) show that viscoelastic fluid flooding can lower the residual oil saturation in cores of different wettabilities. The main forces to mobilize the residual oil by viscoelastic fluids are not entirely the same as that of Newtonian fluids. It is not only a force perpendicular to the oil-water interface overcoming the restraining capillary force, but also a viscous dragging force parallel to the oil-water interface that mobilizes the residual oil.