bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Model for Geomechanical Seismicity Based Reservoir Characterization Including Reservoir Discontinuity Orientations
Authors: Hosseini S. Mehran , Aminzadeh Fred 
Published: September 2013

Abstract
Seismicity based reservoir characterization (SBRC) is a reservoir characterization method based on seismic events. This paper focuses on seismicity based permeability estimation which has been used in the oil and gas industry for more than a decade. However, the geomechanical processes behind this phenomenon have not been fully considered in the permeability estimation. A new model for SBRC based on radial pore pressure diffusion in the reservoir and Mohr-Coulomb failure criteria is proposed. This model includes reservoir stress state, fault friction coefficient and discontinuity orientations which were not included in the previously published models. Seismic data from the German Continental Deep Drilling Project (KTB) is used to test the validity of the new model. Our model predicts KTB's reservoir permeability to range between 10−17 to 10−16 m2, which perfectly matches the reported permeability in the literature for KTB and is bounded by the crust permeability limits measured in different studies worldwide. Based on the events front, reservoir discontinuity orientations can also be characterized. Sensitivity analyses of the effects of fault friction coefficient and geometry on estimated permeability showed significant dependency of the estimated permeability on the mentioned parameters. Previous SBRC models did not include permeability estimation dependency on reservoir geomechanical properties and reservoir discontinuity orientations. The new model captures the physics of microseismic activities due to fluid injection and includes geomechanical and reservoir discontinuity properties that were not included in previously published models. Using the new model, based on the events front, one can characterize the orientation of discontinuities that can be activated due to fluid injection which can be used as a new method for fracture network characterization in a fractured reservoir.
Analytical Solutions for Gas Displacements with Bifurcating Phase Behavior
Authors: Khorsandi Saeid , Johns Russell T. , Ahmadi Kaveh 
Published: September 2013

Abstract
Minimum miscibility pressure (MMP) is one of the most important parameters in the design of a successful gas flooding process. The most reliable methods to calculate the MMP are based on slim-tube experiments, 1-D slim-tube simulations, mixing cell calculations, and the analytical methods known as the method of characteristics (MOC). The calculation of MMP using MOC is the fastest method because it relies solely on finding the key tie lines in the displacement path. The MOC method for MMP estimation in its current form assumes that the composition path is a series of shocks from one key tie line to the next. For some oils, however, these key tie lines do not control miscibility and the MMP calculated using the key tie line approach can be significantly in error. The error can be as high as 5,000 psia for heavier oils or CO2 displacements at low temperature where three-phase hydrocarbon regions can exist (L1-L2-V). At higher pressures, the two- or three-phase region can split (or bifurcate) into two separate two-phase regions (L1-L2 and L1-V regions). Thus, for the MMP calculation from MOC to be correct we must calculate the entire composition path for this complex phase behavior, instead of relying on the shock assumption from one key tie line to the next.
In this paper the MOC composition route is developed completely for the bifurcating phase behavior displacement using a simplified pseudoternary system that is analogous to the complex phase behavior observed for several real displacements with CO2. We develop the MOC analytical solutions by honoring all constraints required for a unique solution; velocity, mass balance, entropy, and solution continuity. The results show that a combination of shocks and rarefaction waves exist along the nontie-line path, unlike previous MOC solutions reported to date. We show that by considering the entire composition path, not just the key tie lines, the calculated MMP agrees with the mixing cell method. We also show that in this complex ternary displacement the displacement mechanism has features of both a condensing and vaporizing drive, which was thought to be possible only for gas floods with four or more components. For pure CO2 injection the solution also becomes discontinuous for oils that lie on the tie-line envelope curve. Finally, we show that shock paths within the two-phase region are generally curved in composition space and that there is no MMP for some oil compositions considered in the displacements by CO2. Recovery can be large even though the MMP is not reached.
Using Completion Diagnostics to Optimize Completion Designs in Several Horizontal Shale Plays
Authors: Johnson M. D. , Pechiney J. J. , Warren M. N. , Woodroof R. A. , Leonard R. S. , Moore C. P. 
Published: September 2013

Abstract
Horizontal shale gas and oil completion designs have evolved over the last several years. Effective completion design has become extremely important in developing these shale plays. In general, the industry has moved towards longer laterals, more stages, closer spacing between entry points, and increased proppant and fluid volumes. The use of completion diagnostics can be applied to supplement production data and stimulation modeling in optimizing the completion designs and reducing the slope of the learning curve in these emerging shale plays. Fluid and proppant tracer technologies and production profiling have been successfully employed in this optimization process. This paper will present several case histories demonstrating how these completion diagnostic tools have been successfully deployed to assess stimulation effectiveness. Case histories will be presented from the Marcellus, Eagle Ford, Haynesville, and Woodford shales in which these technologies have been employed to characterize proppant placement and load fluid clean-up and to quantify fluid and proppant communication between wells. In these case histories, the diagnostic results were used to evaluate perforation design, fluid and proppant placement as a function of the perforating scheme, lateral coverage, and fluid clean-up as it relates to lateral length, wellbore trajectory, changes in lithology, and frac fluid design.
This paper will characterize and validate the role of completion diagnostics in the completion optimization process.
Eagle Ford Shale: Hydraulic Fracturing, Completion and Production Trends, Part III
Authors: Centurion Sergio , Cade Randall , Luo Xin Lucy , Junca-Laplace Jean-Philippe 
Published: September 2013

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. However the resultant multiphase fluid production, along with reservoir heterogeneity that is typical of most unconventional reservoirs, adds complexity and risk to development, especially for completions.
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 4,000 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 for this case study was laid first in SPE 149258 (2011) and then in SPE 158501 (2012). This last paper summarized production, completion techniques and hydraulic fracturing stages performed in 57 Eagle Ford wells. Since the previous papers, many new wells have been completed, considerably expanding the data available for analysis. Completion volumes, well architecture and reservoir character are analyzed. 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.
Reservoir-Condition Pore-Scale Imaging Of Supercritical Carbon Dioxide
Authors: Andrew Matthew , Bijeljic Branko , Blunt Martin J. 
Published: September 2013

Abstract
We present the results from a novel experimental apparatus that can image – at the micron scale – fluid displacements at elevated temperatures and pressures. The images are acquired using a micro-CT scanner (Xradia Versa 500) that has been adapted to allow core flood experiments to be conducted in situ, allowing continuous imaging at resolutions down to around 1 µm. A small cylindrical core – approximately 6 mm in diameter – is placed in a carbon fibre core holder that allows high pressures and temperatures to be imposed, while remaining largely transparent to x-rays. Fluids are injected into this mini-core holder, with flexible tubing to allow the core to rotate during scanning.
We use this apparatus to study the displacement of supercritical carbon dioxide by brine, with application to carbon storage in aquifers. We study displacement in carbonate and sandstone rocks. Experiments in carbonates introduce additional challenges, since the carbon dioxide, brine and rock need to pre-equilibrated to prevent dissolution of carbon dioxide and chemical reaction (dissolution) with the rock during the experiments: this then reproduces conditions in the centre of a carbon dioxide plume where local thermodynamic equilibrium has been reached.
We study displacement in Ketton limestone and Bentheimer sandstone. Both rocks have large inter-granular pores. In Ketton there is also significant intra-granular micro-porosity that remains brine-saturated during the experiments. We study primary drainage (injection of carbon dioxide) followed by secondary imbibition (injection of brine). We image the distribution of the phases during and at the end of the experiment.
We show that significant quantities of carbon dioxide can be trapped as a residual phase in the pore space of both rock types, with a saturation matching that measured in core-scale (cm scale) experiments (0.202±0.012 in Ketton and 0.320±0.009 in Bentheimer). Trapped ganglia of all sizes are observed, with an approximately power-law distribution of size. The exponents for the power laws are larger than expected through percolation theory (2.189 as against measured values of 2.39±0.12 in Ketton and 3.0±0.3 in Bentheimer). We can observe how the supercritical carbon dioxide is displaced at the pore scale during waterflooding, providing a benchmark dataset for pore-scale modelling and further analysis.
Overall, this work presents a novel methodology for in situ reservoir-condition pore-scale multi-phase flow analysis, accounting for phase exchange and chemical reaction. In application to carbon storage, we show that significant amounts of carbon dioxide can be trapped as a residual phase in both quartz and calcite rich rocks.
Design Methodology for Swellable Elastomer Packers for Well Construction Operations
Authors: Evers Rutger , Koløy Tom Rune , Abrahamsen Terje 
Published: September 2013

Abstract
Since the introduction of swellable technology to the oilfield in 2001, its acceptance has grown significantly, and the scope of applications has expanded accordingly. Most of its usage has been in applications in horizontal, multi-zone fracturing, and in combination with inflow control devices (ICDs) and screens during the completion phase of the wells.
One application that is gaining interest globally is the use of swellable tools during the well construction phase. The main objective here has been to provide extra sealing capability in addition to that of the cement sheath to prevent a micro-annulus or a mud channel when the packers are cemented in. In certain cases, swellable elastomer packers (SEPs) are designed to provide a full redundant seal above the top of cement (TOC).
There are several reasons why SEPs and cementing operations are a good fit; primarily, the application of the technology is simple to implement, and allows pipe movement during the cement job. One other advantage is the fact that no specialized personnel are required for packer installation.
However, several implications to the use of SEPs in combination with a cement job must be considered:
Packer design and impact on cement placement; the packer must not impact the cement placement, as the main objective of a cement job is to get the cement slurry placed properly. Impact of swelling rubber on cement matrix once the cement is in place, it is important to know whether the SEP will impact the hydration process (setting) of the cement, changing the properties of the set cement. Bonding at the cement/rubber interface; the bond at the cement/rubber interface must be confirmed.
This paper discusses the issues above, and benefits that can be expected when SEPs are used during well construction. Two case histories will be presented to illustrate the use of SEPs during the well construction phase.
Deepwater Wells Top Hole Cement Volume Evaluation using Innovative Hole Size Inversion from LWD Propagation Resistivity Measurements
Authors: Peternell Ana , Dooply Mohammed , Leveque Soazig , Tovar Gioconda , Horkowitz Jack 
Published: September 2013

Abstract
Following the Gulf of Mexico Deepwater drilling moratorium in 2010, the industry focus towards well integrity assurance has significantly increased. Several new and updated regulations and best practices have been published in the last two years, including API Standard 65 – Part 2 and API RP 96. These two industry accepted standards highlighted that determining the hole volume to confirm the cement slurry volume, to fill-up the annulus to the designed top of cement, is one of the many factors impacting cement placement success during well construction process.
A new solution for riserless section was developed based on existing Logging While Drilling (LWD) electromagnetic propagation resistivity measurements, which meets the requirement to understand hole volume drilled with water based mud in deepwater environment.
Historically, deriving an accurate caliper from LWD electromagnetic propagation resistivity measurements has never been easy due to big uncertainty of mud resistivity (Li et al, 2003). The implementation of a novel simultaneous inversion model and forward modeling database from standard 2-Mhz propagation resistivity, for water-based mud (WBM) and large boreholes, provided the solution to overcome that uncertainty (Whyte et al, 2012).
This novel solution was specifically developed to address the needs for the riserless top-hole sections of high cost deepwater wells: from cement volume calculations, identification of borehole degradation through time, and new opportunities for identification of shallow water flows using the full capacity from the inversion process.
The extensive validation of this innovative approach with wireline mechanical calipers in numerous hole sections resulted in far better results than initially anticipated (Whyte et al, 2012). The information obtained provided significant insights into the reliability and limitations of the current algorithm. The ability to monitor the borehole size while drilling, as well as analyzing the reaming and trip out passes from recorded data, makes this measurement a valuable source of time-lapse information. The next validation process consisted in the comparison between cement volumes computed using these measurements against identification of cement returns during riserless cementing operations in deepwater wells.
The LWD caliper derived from propagation resistivity measurement was analyzed in more than a dozen of wells in Gulf of Mexico. Spefic case studies covering the drilling and cementing operations are presented in this paper.
Hydraulic Fracture Propagation from Infill Horizontal Wells
Authors: Roussel Nico P. , Florez Horacio A. , Rodriguez Adolfo A. 
Published: September 2013

Abstract
As pressure increases or decreases non-uniformly as a result of well injection/production, stresses vary anisotropically in the reservoir. The principal stresses, which govern the propagation direction of hydraulic fractures, are thus modified not only in magnitude but also in direction. Previous modeling efforts and field observations have demonstrated the impact of stress reorientation on the refracturing of vertical wells and the multi-stage fracturing of horizontal wells.
Using a state-of-the-art coupled symmetric Galerkin boundary-element method (SGBEM) and finite-element method (FEM) model, we simulate the impact of prior production from offset wells on the propagation direction of fractures initiated from an infill horizontal well. Geomechanical calculations demonstrate the occurrence of stress reversal in the infill region following a period of production from the offset wells in the order of years. The numerically simulated hydraulic fracture network in the infill well is shown to contact a smaller reservoir area past the onset time of stress reversal, as the induced fractures gradually turn to orient parallel to the infill well. The risk is to see the performance of the infill well drop compared to the offset wells. On the other hand, a window of opportunity exists when the horizontal stress contrast is reduced compared to in-situ, thus favoring the interaction with natural fractures and enhancing fracture complexity.
These new observations have significant implications for field development strategies, hydraulic fracturing design, well placement and spacing, as well as the timing of infill-well stimulation, especially in shale plays where poroelastic stress reorientation is sustained over the life of the reservoir.
Defining Three Regions of Hydraulic Fracture Connectivity, in Unconventional Reservoirs, Help Designing Completions with Improved Long-term Productivity
Authors: Suarez-Rivera Roberto , Behrmann Larry , Green Sid , Burghardt Jeff , Stanchits Sergey , Edelman Eric , Surdi Aniket 
Published: September 2013

Abstract
Using large-scale hydraulic fracturing experiments on tight shale outcrops we identified three dominant regions controlling stage production: (1) the connector between the wellbore and the fracture system, (2) the near-wellbore fracture and (3) the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir fabric, its relation to the in-situ stress, and the distribution of rock properties. However, these regions are always well differentiated. Understanding the role of each of these components, to hydrocarbon production, is fundamental to identify the dominant sources of loss of fracture conductivity and accelerated production decline. The conditions promoting the loss of fracture conductivity, fracture face permeability and surface area in contact with the reservoir vary significantly along the length of the hydraulic fracture. By separating the induced fractured area into three characteristic regions of reservoir contact, we isolate the dominant drivers of loss of production per region, and obtain the best compromise for sustained stage productivity. We used large-scale hydraulic fracturing experiments to develop and validate the concept. These were integrated with scaled-down measurements of fracture conductivity, proppant embedment and the effect of rock-fluid sensitivity. We find that the critical conditions for productivity for the wellbore-connector depends on mechanical stability considerations and are independent of reservoir quality. The critical conditions for productivity from the near-wellbore fracture are solids retention in the proppant pack, and reduction of fracture face permeability due to proppant embedment. The critical conditions for productivity from the far-wellbore fracture are loss of surface area and retention of fracture conductivity. Results provide a framework for improving fracture design for improved long-term productivity. This is achieved by understanding the conflicting requirements between three regions of flow within the fracture and selecting the optimal compromise between these.
Selecting the Optimal Spacing Pilot Design for Unconventional Resource Optimization
Authors: Coopersmith Ellen , Burkholder Kent , Schulze Jan , Monette Scott 
Published: September 2013

Abstract
Spacing pilots are the most discussed and debated pilots considered for unconventional resource plays because they provide the greatest opportunity to maximize the value derived from an asset by optimizing the number of development wells. Determining optimal spacing early in a field's development allows companies to affect the largest amount of acreage. Determining the optimal spacing late may result in under or overdevelopment of all or large portion of the acreage.
Interestingly, spacing pilots in unconventional plays tend to differ from those in conventional, which is a matter of debate and caution addressed in this paper. Conventional field spacing pilots are often trying to understand drainage from individual wellbores, to answer the question of how many wells are needed to produce the estimated resource in a given acreage tract; in which case, the fewer the wells, the higher the value. In unconventional reservoirs, however, the industry tends to take a very different approach. A typical well performance type curve is forecast for a given well and completion design. Unconventional spacing pilots are then designed to try to understand the minimum distance between lateral wellbores before interference occurs and the wells produce each other's resources, thereby degrading type curve performance. In this case, the more wells, the higher the value.
The challenge lies in the early and efficient evaluation of different spacing pilot designs. This is due in part to the inherent complexities involved with unconventional resources: the fact that the optimum spacing is linked both to existing geologic uncertainties and uncertainties in the effectiveness of the well and completion design.
This paper presents a step-wise approach to design and value unconventional spacing pilots, using a typical case study example. The paper demonstrates (1) how to frame spacing pilot design alternatives, (2) forecast the uncertainty reduction potential of each design, and (3) evaluate the business case for the different alternatives. Each step is distinct and necessary to guide the evaluation of this decision. Tips and pitfalls are described and the field optimization decision tree structure necessary to capture the impact of optimal spacing is discussed.