bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geology-guided Quantification of Production-Forecast Uncertainty in Dynamic Model Inversion
Authors: Maucec Marko , Cullick Stan , Shi Genbao 
Published: October 2011

Abstract
The presence of a large number of geologic uncertainties and limited well data typically increase the challenges associated with hydrocarbon recovery forecasting. Although recent advances in geologic modeling enable the automation of the model generation process by means of next-generation geostatistical tools, the computation of the reservoir dynamic response with full-physics reservoir simulation remains a computationally expensive task, which in practice requires considering only a few (but which?) of the many probable realizations.
This paper presents a workflow that demonstrates the potential of capturing the inherent model uncertainty more accurately and assists in production-forecast business decisions. This workflow uses a history matching approach that directly interfaces the Earth modeling software with a forward simulator. It relies on the rapid characterization of the main features of the geologic uncertainty space, represented by an ensemble of sufficiently diverse history matched model realizations at the high-resolution geological scale. This workflow generates a more accurate result by obeying known geostatistics (variograms) and well constraints.
We implement a multi-step, Bayesian Markov chain Monte Carlo inversion in which the proxy model is guided by streamline-based sensitivities. This process eliminates the need to run a forward simulation for each model realization, which significantly reduces the computation time. Efficient model parameterization and updates in the wave-number domain, based on discrete cosine transform (DCT), is used for fast characterization of the main features of the geologic uncertainty space, including structural framework, stratigraphic layering, facies distribution, and petrophysical properties. The application of the history matching workflow is demonstrated with a case study the combines the geological model with approximately 900K cells, four different depositional environments, and 30 wells with a 10-year waterflood history.
Finally, the method is described to dynamically rank the reconciled model realizations to identify the highest potential of capturing bypassed oil and to optimize business decisions for implementing improved oil recovery (IOR). The main features include the following:
Calculation of pattern-dissimilarity distances, which distinguish two individual model realization in terms of recovery response Deployment of very fast streamlined simulations to evaluate distances Application of pattern-recognition techniques to assign several realizations, representative for production forecasting, to full-physics simulation Derivation of the probability distribution of dynamic model responses (e.g., recovery factors) from the intelligently selected simulation runs
Nanoparticle and Microparticle Flow in Porous and Fractured Media: An Experimental Study
Authors: Alaskar Mohammed , Ames Morgan , Connor Steve , Liu Chong , Cui Yi , Li Kewen , Horne Roland 
Published: October 2011

Abstract
The goal of this research was to develop methods of acquiring data about reservoir pressure and temperature, near the wellbore and far out in the formation, and correlating such information to fracture connectivity and geometry. Existing reservoir characterization tools allow for pressure and temperature to be measured only at the wellbore. The development of temperature- and pressure-sensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature and pressure nanosensors. The study investigated parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape and surface charge or affinity to rock materials.
The principal findings of this study were that spherically shaped nanoparticles with surface charge compatible with that expected in porous media are most likely to be transported successfully through formation rock, without being trapped due to physical straining, chemical or electrostatic effects. Silica nanoparticles were passed through Berea sandstone and long slim-tube sand-packs without difficulty. We found that tin-bismuth nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver nanowires was primarily due to their shape. This conclusion was supported by the recovery of the spherical silver nanoparticles with the same surface characteristics. The entrapment of hematite nanorice was attributed to its affinity to the porous media caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particles surface charge.
Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 μm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 μm) as determined by the cubic law.
Quick Estimate of Initial Production from Stimulated Reservoirs with Complex Hydraulic Fracture Network
Authors: Xu Wenyue , Li James , Mike Du C. 
Published: October 2011

Abstract
Models of complex fracture networks created by hydraulic fracturing stimulation have been developed to analyze fracture network growth and proppant placement, mostly for wells drilled into shale gas or tight sand gas reservoirs. However, there is still a lack of quick solutions for estimating the rate of production from these wells analytically. This paper presents a few simplified analytic well production models developed recently based on the laws of mass and momentum conservation, including:
The relative magnitude of pressure drops along fractures and across shale formation The effect of a damaged fracture surface layer on production Solutions for gas flow from reservoir formation into a fracture or parallel fractures with transient fracture fluid pressure Scaling of the rate of this flow with time and fracture spacing Coupling of fluid flows from reservoir formation into and along fractures of a complex hydraulic fracture network
The models were validated against numerical simulations using a commercial simulator for gas production from a single planar fracture, a cluster of parallel fractures and a wiremesh fracture network. These analytical models provide fast and convenient tools for fracturing job design and post-job analysis of hydraulic fracturing stimulation. They may also find potential applications to broader areas.
Evaluation and Improvement of Gravel Pack Treatments Using Advanced Downhole Pressure Analysis
Authors: Wassouf Philip , Jain Samyak , Dannish Greg , Ramnarine Alan 
Published: October 2011

Abstract
Openhole gravel packing (OHGP) is emerging as one of the primary completion techniques in horizontal wells with sanding tendencies. As the experience level for this technique increases, OHGP applications are extending to more challenging environments, including longer intervals. Because many of these jobs are performed in offshore and deep water environments where the cost of failure is substantial, a thorough knowledge of all aspects of treatment design, execution, and evaluation is required. While many OHGPs have been performed, the current understanding of both treatment success and failure is limited due to either a lack of sufficient data (such as bottomhole pressure and temperature) or experience in its evaluation.
This paper introduces data analysis techniques that can be used for a more detailed insight into a variety of downhole events, including packing mechanisms, fluid changes, and system frictions. The pressure analysis technique presented isolates sections of the flow path and identifies these events within the system for accurate treatment analysis. The combination of this technique and volumetric and material balance calculations ensures a detailed quantitative approach to gravel pack data analysis.
The background theory and its application are discussed through a detailed case study of a well in the Poinsettia field, offshore Trinidad, in which downhole gauge data was used to identify and quantitatively analyze the final pack integrity. The analysis technique was able to confirm complete coverage of the screens as well as the packing mechanism by which the gravel was placed. This approach to gravel pack evaluation maximizes the value of downhole memory gauge data, yielding an improvement in the knowledge of downhole processes and facilitating the continuous improvement of OHGP job design and execution.
Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs: Lessons Learned in the United States
Authors: Flores C. P. , Holditch S. A. , Ayers W. B. 
Published: October 2011

Abstract
Development of unconventional hydrocarbons is increasingly important as conventional resources decline and oil and gas demand increases. The concept of the energy resource triangle (Masters 1979) suggests unconventional oil and gas are abundant, but the exploitation of these resources is particularly sensitive to both technology and commodity prices. In this paper, we assess the effects of technology and various geopolitical and economic events on historic U.S. unconventional oil and gas production, in the context of Master's resource triangle theory (RTT).
We used the Austin Chalk as the base case and then extended the study to seven other unconventional plays. The two approaches used to evaluate the RTT were: (1) correlation of commodity prices and technology with drilling activity, and (2) production forecasting using decline curve analysis. Spearman's Rank Correlation Coefficient was used technique to establish the dependence between active wells, rig count, and commodity price variables. Decline curve analyses allowed us to estimate the increase in production from different scenarios of high price or technology.
Results support the RTT concept: higher commodity prices encouraged the introduction of new technologies, and increased drilling activity and boosted production from unconventional plays. For example, horizontal drilling revived older plays, such as the Austin Chalk. Moreover, the combination of horizontals wells and advanced fracture stimulation techniques led to the expansion of shale plays such as the Barnett and the Bakken. Correlation of commodity prices with drilling activity demonstrated that, during periods of high commodity prices, the number of producing wells increased an average of 75%. Using decline curve analysis, a maximum of $50 billion oil and gas production was forecasted via vertical, fractured wells (conventional technologies) and an economic cutoff of 5 BOE/d/well. However, current production plans, using improved technologies, suggest that the assessed plays may produce an additional $320 billion oil plus gas.
U.S. production from unconventional reservoirs, stimulated by a federal tax credit, technology advances, and high commodity prices, encourage operators to dip lower into the resource triangle. Lessons learned in the U.S. may encourage the exploitation of unconventional oil and gas worldwide.
Best Practices for Effective Use of Technology in the Classroom
Authors: Fiffick William S. , Smith Michael R. 
Published: October 2011

Abstract
Classroom training takes on a more crucial role as engineers, scientists, technologists, and operations personnel are challenged to solve new and more complex problems; the ability to properly apply oil field technology becomes even more crucial to our success. While much of the training provided to those entering the workforce is built on foundational concepts, products, and processes, much more is required. New applications of computer technology, processes, practices, and products are constantly being invented, refined, and/or improved. The ability to quickly and systematically apply new technology can save hundreds of work hours. Applying new technology can also pay great dividends by helping new field engineers learn technology and foster continuous improvement. Conventional teaching methods are still viable today in specific situations. The use of computers and proprietary software requires different processes and new methods of instructional delivery. To facilitate the process, computer software management tools can greatly enhance the teaching process. So, how do we capture that knowledge and those lessons learned? What best practices can be modeled? How do we leverage learning technology to archive and transfer these important lessons? How do we optimize the time commitments from our instructors? What emerging technologies are available which may assist with the capture, transfer, and delivery efforts? How are the varied learning methodologies satisfied?
The following is a case study from a major oil field services company outlining effective and efficient technology transfer efforts in the classroom. Best practices as well as lessons learned are discussed.
Deep Fracture Imaging Around the Wellbore Using Dipole Acoustic Logging
Authors: Bolshakov Alexei , Patterson Doug , Lan Chun 
Published: October 2011

Abstract
Characterizing fractures in reservoir rocks is important because they provide critical conduits for hydrocarbon production from the reservoir into the wellbore. The standard method uses shallow borehole imaging services, both acoustic and resistivity, which essentially look at the intersection of the fractures at the borehole wall. Cross-dipole technology has extended the depth of evaluation some 2 to 4 ft around the borehole by measuring the fracture-induced azimuthal shear-wave anisotropy. A recently developed shear-wave reflection imaging technique provides a method for fracture characterization in a much larger volume around the borehole with a radial extent of approximately 60 ft. This technique uses a dipole acoustic tool to generate shear waves that radiate away from the borehole and strike a fracture surface. The tool also records the shear reflection from the fracture. The shear-wave reflection, particularly the SH waves polarizing parallel to the fracture surface, is especially sensitive to open fractures, enabling the fractures to be imaged using this dipole-shear reflection data. We use case examples to demonstrate the effectiveness of this shear-wave imaging technology that maps fractures up to 60 ft away and even detects fractures that do not intercept the borehole.
New Acoustic Log Data Interpretation for Gas-bearing Shaly Sands
Authors: Lan Chun , Patterson Douglas J. , Tang Xiaoming 
Published: October 2011

Abstract
Acoustic wave propagation in a sandstone formation depends on porosity, mineralogy, rock matrix elastic moduli, and fluid saturation. The wave velocities are directly linked to pore space compressibility, which forms the basis of many acoustic interpretation methods for identifying gas-bearing sands, e.g., Castagna's cross-plot method and Murphy et al.'s modulus decomposition method, etc. The latter method detects the presence of gas by comparing acoustic log data with synthetic data computed for full saturated water, oil and water conditions. A basic assumption of this method is that the ratio of the bulk and shear moduli under gas-saturation is invariant for sandstones. This assumption limits the application of this method only to the clean sand scenario. For shaly sands with significant clay content, this moduli ratio is not a constant value, and the interpretation based on the constant ratio assumption may become invalid.
We developed a new acoustic interpretation method for gas indication in the shaly sandstone formation. This method determines the variation of the dry frame bulk-to-shear moduli ratio by calibrating it in a water-bearing zone. This calibration establishes the correlation between the moduli ratio and shale content. The established correlation is then applied throughout the zone of interest to calculate pore fluid bulk modulus and gas saturation. The calculation result enables a direct interpretation of gas-bearing sands. To apply this method, acoustic compressional and shear velocity, gamma ray, and density log data are required. In case there is no water-bearing zone for the calibration, default ratio values can be used.
This method has been successfully tested in several wells. Two examples are used to demonstrate the method and its application. In both examples, the new results are compared with those from Murphy et al.'s method to demonstrate the marked improvement of the new method for shaly sands. Neutron and density results and resistivity log data further validate the new results.
Joint Inversion of 4D Seismic and Production Data
Authors: Landa Jorge L. , Kumar Dhananjay 
Published: October 2011

Abstract
We present a workflow for the quantitative integration of 4D seismic and production data into reservoir simulation models. Reservoir models are probabilistically history matched to 4D seismic and production historical data simultaneously. The timely incorporation of 4D seismic into reservoir models, coupled with the associated reduction of production forecast uncertainty, has a significant impact in the modern reservoir management of oil and gas fields. One of the outstanding features of the work presented is the use of the 4D seismic data at the seismic trace level (i.e. seismic wiggle) compared to the impedance level.
In the joint inversion approach, the reservoir models are jointly calibrated to the production data and the 4D seismic data simultaneously through a single inversion process. There is no need for separate seismic inversion for impedance or for pressure/saturation. The calibrated reservoir models honor both the historical production data and the 4D seismic traces.
The joint inversion ensures consistency among the observed 4D seismic traces, the observed production data, and the geological, seismic, petrophysical and flow models. This consistency, while it is guaranteed in the joint inversion, is difficult to attain through the traditional approach of separate inversion processes for 4D seismic and production data.
The joint inversion process seeks: a) to shorten the time between 4D seismic acquisition and its incorporation into reservoir models, b) to use 4D seismic in a quantitative way, and c) to reduce uncertainty in reservoir models and thus reduce uncertainty in the production forecasts.
This paper presents and discusses results from application of the joint inversion workflow to a synthetic field case based on a real field. The example covers the areas of a) history matching of flow simulation models to 4D seismic and production history, and b) estimation of uncertainty.
The joint inversion process requires a multidisciplinary effort. It involves the joint modeling of geology, flow simulation, rock physics, and seismic modeling under a common earth model, and thus it naturally fosters the efficient interaction among geologists, geophysicists, and reservoir engineers.
Improvement of Flow Properties of Heavy Oils Using Asphaltene Modifiers
Authors: Ovalles Cesar , Rogel Estrella , Segerstrom John 
Published: October 2011

Abstract
The presence of asphaltenes and its tendency to form aggregates play a fundamental role on the high viscosity observed for heavy and extra heavy crude oils (H/XH). It has been shown that by removing the asphaltenes, a reduction of two to three orders of magnitude on the viscosity of the deasphalted product is obtained. It has also been demonstrated that asphaltenes interact extensively within themselves and with other similar molecules forming extended networks. By this way, the asphaltene solutions have relatively high viscosities and, these values increase exponentially with the concentration. In this work, the viscosity of H/XH is reduced by the use of additives that can act as modifiers of the aggregation behavior of asphaltenes. Several commercially available additives were evaluated at high (0.1-3%) and low (50 up to 400 ppm) concentrations at laboratory (20 mL) and bench (8 L) scales. For an extra heavy crude oil/diluent blends (75/25 wt.), the presence of the additives led to viscosity reductions up to 18 to 25% with respect to the blend without additives. Particle size measurements indicated that the presence of the Asphaltene Modifiers shifted the asphaltene distributions from "flocculated" (&gt;1 µm) to "stabilized" asphaltenes (~0.1 µm) and give evidence of the effect of these additives on the aggregation behavior of asphaltenes. The commercial applications of these additives are also discussed.
The Effect of Mechanical Properties Anisotropy in the Generation of Hydraulic Fractures in Organic Shales
Authors: Waters George A. , Lewis Richard E. , Bentley Doug C. 
Published: October 2011

Abstract
Organic shale reservoirs have very low matrix permeabilities. An extensive conductive hydraulic fracture network is necessary to impose a pressure drop in the formation to produce hydrocarbons at an economic rate. In addition, horizontal wells permit the initiation of multiple hydraulic fractures within the reservoir section of the organic shale. The location of the lateral landing point can have a significant impact on hydraulic fracture geometry.
The stimulated fracture system is influenced by the extensive horizontal laminations that are pervasive in shale reservoirs. The laminations will strongly influence the hydraulic fracture height because of the difference in rock mechanical properties measured normal and parallel to the bedding planes. In order to accurately predict fracturing height from logs in this environment, these mechanical property differences must be taken into account.
A series of sonic logs have been run in organic shales and the stress profile generated from these logs has been estimated, accounting for the difference in mechanical properties in the vertical and horizontal directions. This stress profile has been calibrated to measured closure stresses acquired in-situ via micro-fracturing of multiple intervals in vertical, openhole environments. The results show that ignoring the impact of mechanical property anisotropy can lead to significant errors in the estimation of hydraulic fracture height. Correspondingly, the optimal landing point of a horizontal wellbore may not be selected when ignoring this effect. This can result in excessively high fracture initiation pressures, difficulty achieving injection rate or proppant placement, and unexpected fracture height growth. Simulations of hydraulic fracture width indicate that thin high-stress intervals can create pinch points that limit vertical fracture conductivity. Each of these factors can result in un-optimized hydrocarbon productivity.