bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiscale Method for History Matching Channelized Reservoirs Using Level Sets
Authors: Han Jichao , Chen Rongqiang , Datta-Gupta Akhil 
Published: September 2016

Abstract
Identification of channel geometry, facies boundaries, and characterization of channel petrophysical properties are critical for performance predictions of channelized reservoirs. Level set methods have shown great promise to effectively parameterize facies boundaries and allow for changing channel geometry and connectivity during history matching. An outstanding challenge is efficient updating of channel geometry as well as channel petrophysics during history matching. Also, seismic data can provide important information and needs to be used as constraints.
In this paper, a novel two-step history matching workflow is proposed where the channel geometry is modeled using level sets and the internal heterogeneity within the channel facies is modeled using parameterization with linear basis functions, specifically the Grid Connectivity Transform (GCT) basis. Facies boundaries are first represented by the level set function where seismic information is incorporated and the boundaries are gradually moved by solving the level set equation under the seismic constraints. For history matching, Markov Chain Monte Carlo (MCMC) method is employed to minimize production data misfit by adjusting channel geometry and channel petrophysics.
The proposed approach is applied to both 2D and 3D examples. First, we examine the effectiveness of the level set approach by comparison with other approaches for channelized reservoirs, such as Discrete Cosine Transform and Discrete Wavelet Transform. The level set approach is shown to outperform other methods significantly in terms of reproducing channel geometry. Second, we show that the use of seismic constraints helps preserve the structure of facies distributions and geologic realism during history matching. Finally, calibrated facies models are further updated by adjusting the internal channel permeability distributions to fine-tune the history matching. The permeability changes are carried out by perturbing the coefficients of the GCT bases. High and low permeability regions are clearly depicted within the channels and production data misfit is significantly reduced during this second stage. We demonstrate the power and utility of the approach using both 2D and 3D applications.
Previous approaches focused on conditioning channelized models to well data but seismic constraints in level set were not considered. The successful integration of seismic constraints can help not only improve channelized reservoir history matching performance significantly, but also extend applicability of the level set method from simple channelized models to more complicated ones. Also, the GCT approach, for the first time, is shown to capture internal heterogeneity of the channel architecture.
Microseismic Feedback Enhanced Real-Time Diversion Evaluation in Mancos Shale, Piceance Basin Completions
Authors: Scott E. L. , Cape J. H. , Mahrer K. D. , Li N. , Childers A. R. 
Published: September 2016

Abstract
This hydraulic fracture stimulation case study in the Mancos Shale, Piceance Basin used real-time microseismic imaging to evaluate and guide changes to diversion strategies. The objective was to identify and improve hydraulic fracture development of three neighboring, horizontal, and parallel wells.
Black Hills Exploration and Production, Inc. (BHEP) hydraulically fractured three wells using a plug-and-perforate completion technique. All injection stages used the same treatment fluids and proppant types and differed by perforation schemes and diversion strategies. Diversion strategies included combinations of ball sealers and clean fluid sweeps (i.e., fluid without proppant), separating proppant-laden, ramped segments. Stages included one, two, or three proppant segments. The study included microseismic imaging, which acquired data using two deep geophone arrays in nearby wells. The microseismic data were processed during active injections (i.e., in real time). Following each stage, the on-site engineers compared the microseismic event distributions before and after diverters to evaluate diversion effectiveness. Differing microseismic distributions (e.g., changes in shape, azimuth, extent, etc.) combined with bottomhole pressure responses (e.g., increases and breakdowns) indicated successful diversion. Based on design, successful diversion strategies were repeated.
Normally, an on-site engineer assesses diversion success using only the bottomhole pressure response. For this project, the assessment was substantially enhanced by combining bottomhole pressure response with microseismic imaging. As a result of this strengthened assessment, the on-site engineers concluded two main results during the study: (1) ball sealers separating proppant segments led to successful diversion and (2) a clean fluid sweep or a second set of ball sealers separating three proppant segments was less effective than two proppant segments. After identifying these findings, the engineers changed subsequent stages to include one set of ball sealers separating two proppant segments.
In this study, reducing the number of proppant segments: (1) increased the stages per day by 10% and (2) increased the proppant load per fluid volume by 7%. In addition to these increased operational efficiencies and cost savings, this diversion evaluation and real-time changes improved perforation cluster efficiency (percentage of producing perforation clusters). For the three wells studied, production logs showed 3–24% greater perforation cluster efficiency than other local wells without diversion.
Further Discuss the Roles of Soaking Time and Pressure Depletion Rate in Gas Huff-n-Puff Process in Fractured Liquid-Rich Shale Reservoirs
Authors: Yu Yang , Li Lei , Sheng James J. 
Published: September 2016

Abstract
Cyclic gas injection (CGI), also known as huff-n-puff process, has been demonstrated as the most effective and promising IOR solution in shale reservoirs. Such process involves many operating parameters that can affect the recovery performance in different degrees. As soaking time and pressure depletion rate (PDR) are the two crucial factors, this study aims to further investigate their roles in the oil recovery process of CGI experimentally and numerically.
A total of ten series of the N2 huff-n-puff tests were performed on oil-saturated Eagle Ford shale plugs in a matrix-fracture system. With the injection pressure (Pin) of 1,000 psi, two groups of tests were conducted: 1) under a constant PDR in blowout and five soaking times changed from 0.25-hr to 48-hr; 2) under a constant soaking time of 12-hr and four pressure depletion times changed from 0.05-hr to 48-hr. With the Pin of 5,000 psi, the CGI tests were performed under 12-hr soaking time and blowout pressure depletion to study the effect of Pin on recovery efficiency. Lab-scale simulation models were built and tuned to history match the experimental data.
The experimental results show that recovery factor (RF) from a single cycle increases with soaking time within a certain range, and a longer time has no effect on improving oil recovery. For 1,000 psi Pin, during the soaking phase, the system pressure declined rapidly at the first 3 hr and then became stabilized. The pressure drop was relatively low (10 psi) in the first cycle compared with the following cycles. It tended to increase with the number of cycles performed, which was caused by the decrease of oil saturation thus more gas can be injected into the core sample. It reveals that a soaking period is necessary to the oil recovery process. On the other hand, increasing the pressure depletion rate can raise the incremental RF from each cycle. The blowout condition showed the highest cumulative RF. The performance of N2 huff-n-puff with 5,000 psi Pin outperforms the case of 1,000 psi, which can increase the ultimate RF with less cycles. The well-tuned simulation models were used to analyze and optimize the CGI recovery process.
Safe Mechanical Perforation of Pipe with Connected Control Lines
Authors: Denmon Michael , Harive Kevin , Babin Jacques 
Published: September 2016

Abstract
Currently, oil and gas operators face a number of significant challenges, such as meeting increasing demand and using safe and environmentally responsible methods as well as minimizing costs while maximizing the profitability of highly complex operations.
One solution is to achieve a more comprehensive understanding of assets by successfully integrating monitoring and active control systems. This led to the implementation of smart-well completions (i.e., interval control valves, interval control devices, subsurface safety valve systems, and fiber optic monitoring) (Rodriguez et al. 2013).Yet, some companies still resist this technology because of risk concerns, such as valve failures occurring or bypassed pay zones that warrant well intervention being necessary, which involves pipe perforation. When a control line or umbilical line is strapped to the outside of a well completion, risk is increased for the well intervention. In most instances, it is not possible to pinpoint the exact location of the line within a 360° span of the curvature of the tubing. This is because some completion designs without pre-planned indicators of line placement add to the challenges associated with control and data line moving during the running phase of the well completion. Without the ability to locate the line used for communication with downhole devices, the potential for damage exists resulting from conventional methods of explosive perforation. The development of a nondamaging perforation method provides a means to establish needed communication while helping avoid unrecoverable damage to an asset.
Continuous Microfacies Analysis in Clastic Environments Utilizing Pseudo Grain Size Distribution from Electrical Borehole Images
Authors: Yang S. , Aviantara A. , Delius H. , Le Nir I. , Gong H. , Wang K. 
Published: September 2016

Abstract
Sediment particle size and its distribution are fundamental attributes of sedimentary deposits that provide key information for reservoir quality evaluation. Traditional grain-size analysis can only be obtained from laboratory testing on rock samples from cores. In the absence of core or suitable cutting information, borehole images and nuclear magnetic resonance (NMR) logs are basic input data to estimate grain size. Recently several approaches were proposed for grain-size analysis from NMR for depositional environment studies and expandable sand screen design. In this paper, we propose a new approach for the continuous microfacies analysis from pseudo grain-size distribution of borehole resistivity images.
The true size of particles is very difficult to be measured directly from borehole resistivity image, especially when the particle size is less than the tool button size; additionally, correction factors are different for conductive and resistive particles depending on the resistivity contrast. Based on the high resolution resistivity image, we assume that the resistivity of multiple button measurements represents the particle size relatively, similar to the principle of analyzing textural changes within clastic environments using electrical borehole images. The cumulative probability of each resistivity curve represents a similar statistic to that of grain size in laboratory experiments and indicates the different hydrodynamic conditions. In certain geological settings, the continuous microfacies analysis can be achieved from the cumulative frequency curve shape.
Several case studies were performed to verify this new approach in different depositional environments, including a fluvial system, a lacustrine delta and an aeolian deposit. The analysis results are consistent with drilling core data and provide the detailed microfacies information for sand unit correlation analysis in multiple wells. We find this method is robust in the fluvial system and conglomerate-related depositional environments, and but it is very challenging to distinguish the mouth bar and channel fill in a river-dominated delta.
Drilling with Casing Technology Eliminates Wiper Trips, Lost Circulation, Water Influx, and Wellbore Stability in Two Continuous Sections, Saving up to Five Days in Northern Bolivia
Authors: Ibañez Julio C. , Aguirre Edwin C. , Pinto José E. , Tan Ming Zo , Mendez Marco A. 
Published: September 2016

Abstract
This paper discusses the planning process, execution, and results of casing-while-drilling (CwD) operations in northern Bolivian fields that are historically plagued with problems of water influx, wellbore instability, lost-circulation, and severe bit wear. This paper will discuss why the selection of drillable casing bits is critical to ensuring successful drillout of the same type of polycrystalline diamond composite (PDC) casing bit.
Formation drillability and suitability of well designs in targeted problematic fields, namely Yapacaní, Cobra, and Sirari, are also analyzed to ascertain whether CwD is a viable solution to tackle drilling challenges. A collection of conventional drilling data for six oil wells was provided for the analyses. At the end of the project, CwC technology successfully reduced operational time by 70% on average by improving drilling efficiency and mitigating drilling hazards.
Novel Method for Evaluating Shale Gas and Shale Tight Oil Reservoirs Using Well Log Data
Authors: Freedman Robert , Rose David , Sun Boqin , Brown Ronald L. , Malizia Thomas 
Published: September 2016

Abstract
This paper introduces a novel method for improved evaluation of shale gas reservoirs, shale tight oil reservoirs, and immature organic shale source rocks. The method provides exact and original algebraic equations for determining total porosities, producible fluid volumes, total hydrocarbon volumes, kerogen volumes, and immobile hydrocarbon volumes. The determination of accurate porosities and fluid volumes in organic shale reservoirs is critical for formation evaluation considering the low porosities (3 to 8 p.u.) typically found in shale reservoirs.
We analyze the challenges associated with interpreting logging tool responses in poor quality shale reservoirs and propose a suite of logging tool measurements that are most likely to overcome the problems. A small set of logging tool measurements (i.e., three or four) that have known responses to fluid and solid volumes and have negligible surface effects were selected. Thus our approach aims to circumvent the interpretation problems caused by poorly understood complex fluid-surface interactions that are exacerbated in shales by high surface-to-volume ratios and clays and other conductive minerals.
The logging tool measurements that we use to predict the shale reservoir properties are bulk densities, nuclear magnetic resonance (NMR) porosities, and total organic carbon (TOC) weight fractions derived from total carbon concentrations measured by a gamma ray spectroscopy tool. The tool response equations for these measurements are written as volume weighted averages of reservoir properties. The producible gas in shale gas reservoirs and the high API gravity producible oils in shale tight oil reservoirs cause the apparent (i.e., measured) NMR porosities to read too low and the apparent density log porosities to read too high. Kerogen also causes the density log porosities to read too high.
The tool response equations are solved simultaneously and exactly to determine shale total porosities, fluid volumes, and kerogen volumes. The solution for the shale total porosity is automatically corrected for light hydrocarbon effects on the density and NMR porosity measurements and for kerogen effects on the density porosities. The exact algebraic solutions or "plug-in formulas" for shale reservoir properties are the main results of the paper. The robustness of these solutions in the presence of measurement noise is studied using Monte Carlo simulations. We discuss the standard deviations of the predicted reservoir properties for different measurement noise levels and the effects of errors in the assumed reservoir fluid and solid properties (e.g., gas density, gas hydrogen index, kerogen density) on the accuracies of the predicted reservoir properties.
The algebraic solutions are used to predict reservoir properties from log data acquired in a shale gas well and a shale tight oil well. The results in both wells are shown to compare favorably with available core data.
New Insights on Chemical Diversion in Carbonate Acidizing: Experimental and Simulation-Based Study
Authors: Nino-Penaloza Andrea , Gomaa Ahmed M. 
Published: September 2016

Abstract
Carbonate acidizing restores and enhances production by dissolving a fraction of the rock to create highly conductive channels or wormholes. Most experimental acidizing studies are focused on acid injection at Constant Volumetric Rate (CVR) rather than at Constant Injection Pressure (CIP). A recent study highlighted the benefits of each injection technique for 15% wt. HCl acid. Formations with high injectivity should be treated at CVR as efficient wormholes can be propagated with less acid volume. Aditionally, the increasing injection rate characteristic of CIP can be beneficial in formations with initial low injectivity where wormhole dissolution can change from face and conical to dominant pattern.
The injection rate and injection pressure for acid and chemical diverters are important variables because they affect wormholing, treatment distribution, and therefore the overall skin reduction. The primary objective of the present work is to investigate the effect of chemical diversion when acid treatments are injected at CVR and CIP. This study focused on the behavior of a Viscoelastic Surfactant (VES) based acid diverter inside the porous media and its effect on the treatment and wormhole distribution for low and high injectivity formations.
A core-flood study was conducted using Pink Desert Limestone cores with similar permeability to assess the pressure response of the diverter at CIP. Additionally, a 2-D wormhole model was used to describe the acidizing phenomena. This model captures the acid reaction and chemical diversion coupled with Darcy flow. Synthetic scenarios were created to evaluate the effect of each acid injection technique (CVR and CIP) and diversion staging on the post-treatment skin and wormhole length.
The results of these simulations showed that proper staging of a the chemical diverter aided to improve the treatment placement injected at CVR in a long, highly permeable and homogenous zone as shown by smoother wormhole and skin profiles. CIP delivered nearly uniform treatment placement without chemical diverter when applied at the highest rate below fracture pressure in a long, homogenous and low permeable zone.
For a synthetic case of a long and heterogeneous treatment zone, this study confirmed that CIP generated branched wormholing in the high-permeability zones in the early stages of a treatment sequence and did not significantly reduce the skin in the low injectivity layers. Fluid placement turned less efficient as the injection rate increased over the course of the treatment. Based on these results, the simulation outputs suggest that CIP is not an effective diversion technique in long treatment intervals with significant injectivity contrast. Additionally, it was observed that the inclusion of diverter stages can improve the treatment distribution.
Increased Capabilities for Upward Recomplete of Remote Platform Wells
Authors: Denmon Michael , Harive Kevin , Clemens Jack 
Published: September 2016

Abstract
Through-tubing bridge plugs (TTBPs) enable the production of new zones by isolating abandoned zones without requiring a costly and time-consuming workover rig. Previously available hydraulic setting tools were not applicable to all types of well conditions and plugs, often because of extended toolstring length requirements, making them not suitable for wells with limited rigup height capability. A nonexplosive electromechanical setting tool can provide an easy-to-transport, flexible setting tool for all environments.
An electrically controlled motor enables the effective setting of multiple sizes and types of TTBPs, not dependent on the environmental effects on downhole fluid required by hydraulic tools to facilitate the setting process. The tool uses rotational torque converted to linear pull tension and operates independently of downhole conditions, not requiring specialty fluid types or relying on the appropriate fluid availability. Because fluid is not required for operations, a shorter overall tool length is required compared to existing hydraulic or pneumatic tools. The ability to deploy shorter toolstring lengths means that the electromechanical setting tool can be used in a wider variety of scenarios, such as remote platforms or rigless environments.
With the introduction of the electromechanical setting tool to operations, wells that might have been previously suspended because of the availability of a workover rig can now receive timely interventions, efficiently isolating noncontributing zones and enabling the perforation and production of contributing zones. Operators can benefit from rigless operations by accessing new zones at a lower cost and with a faster turnaround, enabling them to benefit from economically advantageous market conditions. The real-time feedback of the electromechanical tool also confirms that the plug has been set at the required tension using a slow and controlled setting method.
This paper presents case histories to illustrate the advantages of the shorter rigup lengths enabled by the electromechanical setting tool; these advantages are made possible by pinpointing instances in which the hydrostatic setting tool methodology would not have allowed recompletion of producing zones. Job data from the electromechanical setting tool are used to illustrate that the slow, controlled set of the TTPBs was achieved within specifications of the plug design, which cannot be confirmed using hydrostatic setting tools. Cost savings and realized production gains are also highlighted in instances in which the electromechanical setting tool was used to increase asset return value.