bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methods For Modeling Dynamic Fractures In Coupled Reservoir And Geomechanics Simulation
Authors: Ji Lujun , Settari A. Tony , Sullivan R. B. , Orr D. 
Published: December 2007

Abstract
Proper representation of dynamic (propagating) fractures is important for modeling applications in which the fracture is directly coupled to a reservoir simulator. Such a model, while once applied only to unconventional fracturing applications is now being developed for conventional fracturing techniques (such as fracturing in low permeability reservoirs) as a more realistic tool for modeling both fracture growth and post fracture production responses.
In an uncoupled model (such as conventional fracturing software) the reservoir coupling is usually simplified to a 1-dimensional leak-off model which lends itself easily to construct dynamic grids for the fracture. However, coupled models will generally require a dynamic fracture propagating through a stationary reservoir/stress grid. This creates a well-known grid effect resulting in oscillation of fracture growth with time, and limiting the stability of the model.
In most unconventional fracturing applications, the fracture volume is small compared to injected fluid volume due to high leak-off, which causes a singularity of mass balance constraint or fluid volume in facture. If one were to use a conventional fracturing model with a dynamic grid, this would result in convergence problems due to the high leak off of injected fluid. Also, what is not represented in conventional models is the influence that high leak-off has on the far-field stresses and pressures, which in turn influences the fracturing mechanics.
It is believed that the use of a fully coupled dynamic model such as the one being developed here will generate more realistic representions of the fracture/reservoir response.
This paper presents numerical techniques necessary for the successful development of such a fully coupled model. Four different methods for representing dynamic fracture propagation were formulated. These four methods take into consideration the mutual influence between dynamic fracture propagation and reservoir flow, treat the fracture as a highly permeable part of the reservoir, and use one (common) grid system to model both dynamic fracture propagation and reservoir flow in a fully coupled manner. The individual methods differ by the algorithms, by which the dynamic modification of the transmissibility for fractured grid(s) is derived, and range from an empirical approach to the use of analytical fracture models.
Water Fracs and Sand Quantity: A Barnett Shale Example
Authors: Coulter Gerald R. , Benton Edward G. , Thomson Clifford L. 
Published: December 2007

Abstract
Chief Oil and Gas, LLC has an active drilling and completion program in the Barnett Shale, Newark East Field, Ft Worth Basin near Ft Worth, Texas, USA. This Mississippian age gas producing reservoir consists of naturally fractured shale. Most hydraulically induced fractures have been observed to be more of a network of fractures, referred to as fracture fairways, than the usual ‘planar’ fractures. These fairways apparently result from opening many of the natural fractures allowing for production. All wells must be hydraulically fractured for economic production. The Barnett Shale hydraulic fracturing trend in the last few years has been to water frac with small concentrations of sand. The water frac treatments reported on here have varied from approximately 600,000 to over 1,500,000 gallons and 120,000 to over 400,000 pounds of sand. Most of the wells have been completed in the lower Barnett with a lesser number in the upper and lower. Results from both types of completions are included in this work.
Production histories versus treatment volume and pounds of sand are presented as well as production decline data. Results indicate a much better correlation of production history with sand quantity than with fluid volume.
Rate Superposition for Generating Pressure Falloff Solutions for Vertical and Horizontal Wells
Authors: Peres Alvaro M. M. , Boughrara Amina A. , Reynolds A. C. 
Published: December 2007

Abstract
Although the Thompson-Reynolds steady-state theory has proved useful for explaining the relation between reservoir physics and the pressure/pressure derivative response for both injection and falloff tests, until now, we have been unable to apply this method to construct analytical solutions for the falloff response. In this work, we remedy this defi- ciency by constructing analytical solutions for the pressure falloff response subsequent to water injection at a vertical or horizontal well. By comparison with a finite-difference simulator using grid refinement and a hybrid grid, it is shown that our multiphase flow solutions are accurate.
The falloff solution can be written as the sum of the single-phase falloff solution based on oil properties at initial water saturation plus a multiphase flow term, which reflects the deviation of the total mobility (in the region contacted by injected water) from oil mobility at initial water saturation. The multiphase term is presented as an integral in the vertical well case and a sum of one to three integrals in the horizontal well case. For the purpose of constructing an accurate estimate of the falloff multiphase pressure change term, one can use a series of onedimensional Buckley-Leverett solutions (one for each integral in the multiphase term) and assume that, throughout the falloff period, the total mobility profile in the reservoir is equal to the total mobility profile that existed at the instant of shut-in. Evaluation of each integral in the multiphase term requires the one-dimensional mobility profile constructed from the Buckley-Leverett solution and a corresponding one-dimensional flow rate profile during falloff.
For linear single-phase flow, it is shown that rate superposition applies and we use this concept in a reasonable but ad hoc way to estimate the rate profiles needed to compute the multiphase pressure term.
It is shown that even in cases where falloff data allows one to accurately estimate the properties of the oil zone, knowledge of the multiphase term is critical in order to obtain an accurate estimate of the mechanical skin factor.
New Test Method for Evaluating Quality of Set Well Cements and to Optimize Additive Use
Authors: Jennings Scott S. , Siddiqui Shameem 
Published: December 2007

Abstract
In recent years lot of attention has been given to well cement density settling and cracks in the set cement by over-treating with expansion additives. Conventional methods that examined both settling and cracking due to expansion in set cements needed optimizing. The new method used a high-resolution X-ray CT (computerized tomography) scanner to quantify density differences and heterogeneities in set cement specimens. For the determination of settling, the CT-scanner was highly effective by looking for gradients in the calculated slice density values. For the examination of cracks in the cement, the CT-scanner was highly effective in locating even very small cracks in the cement matrix.
This paper discusses the results from tests for linear expansion and cracking tendencies using three commercial expansion additives. The data presented also showed density segregation of set cements, which may have potential to cause problems with zone isolation. By applying the evaluation technique involving CT based density, heterogeneity and quality assessment parameters, expansion additives were reduced up to 80% from most previously recommended additive concentrations. Similarly, the CT-based technique allowed a thorough analysis of the density segregation in set cement specimens. Findings from these studies have lead to effective re-designing of cement slurries used for critical oilwell cementing operations.
Multiscale Formation Resistivity Imaging
Authors: Frenkel Michael A. 
Published: December 2007

Abstract
Conventional interpretation of array resistivity log data is based on inversion. Multidimensional (2D, 3D) log inversion methods commonly use a single formation model (SFM) for the entire interpretation process. The SFM approach has severe limitations when executing either joint or sequential inversions. Here we present a new multidimensional array resistivity data inversion method that utilizes log-resolution-dependent multiscale formation models (MFM). Each of these resistivity models corresponds to a single log or a subset of the multi-array logs. The resistivity model for a particular subset is determined by the expected resolution of the subset logs. Each subset can contain one or more of the multiarray data logs.
Our method consists of two main interpretation runs. For the first run, we interpret separate subarray logs using a set of MFMs. For the second, we generate the formation resistivity model or its image by inverting the results from the first in the radial direction. The method is applicable to any array log data acquired in vertical, deviated, or horizontal wells. The test modeling and inversion results are presented.
A Pore-Network Study of the Mechanisms of Foam Generation
Authors: Chen M. , Yortsos Y. C. , Rossen W. R. 
Published: December 2007

Abstract
Understanding the role of pore-level mechanisms of foam generation in porous media is essential to the mechanistic modeling and simulation of foam IOR processes. Different foam models assume different foam-generation mechanisms, leading to substantially different algorithms for foam processes. The three pore-level events that lead to foam formation are snap-off, leave-behind and lamella division. As bubbles are created by any such mechanism, gas saturation increases, causing formation of new bubbles by snap-off and leave-behind as gas drains liquid-saturated pores. On the other hand, lamellae are stranded unless pressure gradient is sufficient to mobilize those that have been created. The initial state of the porous medium as surfactant is introduced (fully saturated with liquid, or already partially drained) also affects the different foam-generation mechanisms. To appreciate the roles of these mechanisms, their interaction at the pore-network level must be studied.
We report here an extensive pore-network study that incorporates these pore-level mechanisms, as foam is created by drainage or the continuous injection of gas and liquid in porous media. Pore networks with up to 8,000 pores are considered, with rules for the formation and movement of foam lamellae by the three mechanisms enforced throughout. The study explores the roles of the mechanisms, and, by implication, the appropriate form of the foam-generation function for mechanistic foam simulation. Results are compared with previous studies. In particular, the network simulations reconcile an apparent contradiction in the foam-generation model of Rossen and Gauglitz, and identify how foam is created near the inlet of the porous medium when lamella division controls foam generation. In the process, we identify a new mechanism of snap-off and foam generation near the inlet of the medium.
A Chemical Approach to Prevent Asphaltenes Flocculation in Light Crude Oils: State-of-the-art
Authors: Marques Luiz C. C. , González Gaspar , Monteiro Jair B. 
Published: December 2007

Abstract
This paper describes the state-of-the-art of the phenomena associated to the flocculation and precipitation of asphaltenes as well as the chemical solution used to prevent these problems in the production tubing of light crude oil(42°API) offshore wells in Santos Basin, Brazil. It is also provided a detailed discussion on the efforts to diagnose this light crude tendency to flocculate its low concentration (0.3 %) asphaltenes and on the approach to chemically-inhibit the phenomena. To assess the so-called asphaltenes deposition envelope of the light crude a mono-phase crude oil sample was collected and a suite of experiments was performed in a PVT analysis cell equipped with a solid detection system. As per this study, it was possible to evidence the reversibility of the asphaltenes flocculation process above the bubble point, meaning that these asphaltenes behave much as macromolecules in solution as predicted by the Hildebrand theory.
It is also described the laboratory procedures used to select commercial asphaltenes flocculation inhibitors (AFI) and how the selected ones were evaluated in the field. Within the scope of the field test the following issues were addressed: - how the AFI injection is performed; -how the AFI-free oil samples are collected for the tests on the well site and; - how the existing analytical procedures had to be adapted and enhanced to evaluate the AFI performance in crude oils with so low asphaltenes concentration.
The lessons learned from this pioneer study and the field test are being incorporated to Petrobras newer light-crude oil exploration and production projects.
Oil and Gas Reserves Estimates: Recurring Mistakes and Errors
Authors: Harrell D. Ronald , Hodgin John E. , Wagenhofer Thomas 
Published: December 2007

Abstract
Although most petroleum reserves estimates are prepared by qualified reservoir engineers and geoscientists, there continue to be recurring mistakes and errors in estimates of reserves. This statement is not intended to be presumptuous in any regard, but is based upon observations made by the authors over many years as independent petroleum consultants for both publicly-owned and private exploration and production companies.
This paper presents and discusses the most common mistakes and errors associated with reserves estimates. In addition, guidelines are offered that, if followed, may help reduce the chance of such errors occurring.
It is the intent of this paper to focus on mistakes made in the preparation of reserves estimates rather than to discuss potentially incorrect applications of petroleum reserves definitions. It is clearly not the intent of this paper to interfere with the necessary judgment the reserves evaluator must employ in preparing reserves estimates.
It is inevitable that adherence to applicable reserves definitions must be recognized in any discussion of recommended practices regarding the estimation of petroleum reserves. A generalized definition of reserves without regard to categories or authorship is: Reserves are estimated remaining quantities of hydrocarbons to be commercially produced from a known accumulation as of a given date under specified definitions and economic conditions.
Challenges in Implementing UBO Technology
Authors: Eck-Olsen Johan , Vollen Elin , Tønnessen Tim 
Published: December 2007

Abstract
In July 2004 Statoil introduced underbalanced drilling technology to the Gullfaks Field offshore Norway. The main driver for this technology was to overcome existing pressure control problems experienced while drilling conventionally through the cap rock in order to reach the reservoir. The project represents the first application of underbalanced drilling offshore Norway. The focus of the process design was on being environmentally friendly; consequently, no hydrocarbons were released to atmosphere or flared during the operation.
This paper addresses the challenges in implementing the UBO technology in Norway. There were issues related to equipment, procedures, standards and personnel. Most of the existing Norwegian requirements and guidelines have been developed for conventional drilling. The UBO surface equipment used by the project had to go through a detailed review and extensive modifications to fulfill the Statoil internal requirements as well as the external Norwegian standards and demands. Special quantitative risk assessment methods and software were developed throughout the project to define risk associated with UBO compared to conventional methods. Procedures, emergency measures and contingencies were established to ensure a safe operational environment for personnel at any time. Interfaces with existing platform production facilities had to be made in order to process produced gas and liquid hydrocarbons thereby ensuring an environmentally friendly operation. Some of the major challenges were related to communication and teams that consisted of personnel with very different backgrounds working towards a common goal, i.e. the production philosophy with automated processes vs. the drilling philosophy with manual processes. High focus was kept on open communication throughout the project.
Risk-based Decision Support for Planning of an Underbalanced Drilling Operation
Authors: Arild Ø. , Nilsen Thomas , Sandøy Malene 
Published: December 2007

Abstract
As a part of planning the first well utilizing underbalanced drilling technology in Norway, a comprehensive risk analysis is performed, comparing risk associated with underbalanced and conventional, overbalanced drilling. The development of a new risk analysis method is described. It is concluded that for the given case, underbalanced drilling reduces blowout risk considerably.
Polymer-Free Fracturing Fluid Exhibits Improved Cleanup for Unconventional Natural Gas Well Applications
Authors: Fredd C. N. , Olsen T. N. , Brenize G. , Quintero B. W. , Bui T. , Glenn S. , Boney C. L. 
Published: December 2007

Abstract
Hydraulic fracturing treatments in unconventional (coalbed and carboniferous shale) natural gas wells have been successful in stimulating gas production. However, the wells often do not perform up to potential following the treatments for various reasons. Some of the factors that can contribute to the relatively poor performance include low coal or shale permeability, complex cleating and natural fracture networks, gas content and adsorption characteristics, water content, and fracturing fluid interaction with formation surfaces. Fracturing fluid damage in coal formations has been shown to cause significant reductions in permeability, and whole gel leakoff into the cleat networks can further impair production. The same damage mechanisms can impair the production of carboniferous shale formations.
To avoid the damage associated with polymer-based fluids, a coal/carboniferous shale-compatible solids-free (CCSF) fluid was developed for unconventional natural gas well applications. The CCSF fluid is a nitrogen-foamed fluid that was designed to be environmentally friendly to minimize risk to ground water that could be contacted during fracturing treatments.
This study investigates the effects of various hydraulic fracturing fluids including conventional polymer-based fluids, water containing friction reducers, and a coal/carboniferous shale-compatible solids-free fluid on coal and shale pack cleanup. Laboratory coal pack cleanup tests demonstrate a significant reduction in retained permeability with polymer-based fluids. In addition, a high cleanup factor (a parameter introduced to provide a measure of the pressure and time required for cleanup) is required to establish only marginal flow conditions with brine injected in the production direction. Even water containing low concentrations of friction reducer may result in less than 50% retained permeability. The CCSF fluid provides 70 to 100% retained permeability and a low cleanup factor for effective coal pack cleanup with coal samples from seven coal basins in North America. Similar improvements were observed with carboniferous shale pack cleanup tests.
Field case histories in coal and carboniferous shale formations are consistent with laboratory observations and demonstrate a dependence of fracture cleanup on retained permeability and the cleanup factor measured in the laboratory. Production results demonstrate a 30 to 60% increase in production with the CCSF fluid compared to conventional fracturing fluids in coal and carboniferous shale basins in the United States.
A Mechanical Methodology of Improved Proppant Transport in Low-Viscosity Fluids: Application of a Fiber-Assisted Transport Technique in East Texas
Authors: Engels J. N. , Martinez E. , Fredd C. N. , Boney C. L. , Holms B. A. 
Published: December 2007

Abstract
Several different hydraulic fracturing treatment design methodologies have been adopted and used with varying success in East Texas and, specifically, in the Cotton Valley Sand Formation. Treatment designs have ranged from massive hydraulic fractures using crosslinked polymer fluids to low proppant concentration slickwater treatments (waterfracs) using only water plus a friction reducer. Operators have varying opinions regarding the benefits of the various design approaches, with the only common conclusion being that hydraulic fracturing must be employed to commercially produce hydrocarbons from these tight formations. The major design challenges include the need for long fractures, relatively limited height growth, good proppant coverage over the entire fracture surface, and low proppant pack damage. Neither conventional fracturing treatments nor slickwater fracturing treatments address all of these issues.
To meet the challenging design requirements, a new design methodology in which fibers are added to the fracturing fluid has resulted in added benefits for operators. The fibers assist in the transport of proppant based on a mechanical suspension mechanism and prevent proppant settling during fracture closure. As a result, the fluid viscosity is no longer the main factor in proppant transport and significantly lower polymer concentrations can be used without compromising proppant transport. For example, the polymer concentration used in several successful treatments at BHST in excess of 250°F has been reduced by about 50% when used in conjunction with the fibers. The lower fluid viscosity allows for the creation of the desired fracture geometry with controlled fracture height growth. In addition, reducing the polymer concentration has largely been accepted as a means to increase fracture conductivity. The use of fibers in conjunction with the polymer fluid is a new approach that has allowed for additional reduction in polymer loadings while still maintaining excellent proppant transport in over 90 jobs pumped to date.
The purpose of this paper is to share the fracture design methodology incorporated for several operators completing wells in East Texas. Typical job designs with fluid rheology and laboratory conductivity data are presented in conjunction with the placement success when using the fiber assisted transport design methodology. Initial production results are reviewed and compared to offset wells that have been stimulated using conventional methods.