bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flowback Analysis for Fracture Characterization
Authors: Abbasi Majid Ali , Dehghanpour Hassan , Hawkes Robert V. 
Published: October 2012

Abstract
Tight reservoirs stimulated by multistage hydraulic fracturing are commonly characterized by analyzing the hydrocarbon production data. However, analyzing the available hydrocarbon production data mainly determines the fracture-matrix interface. This analysis is not enough for a full characterization of the induced hydraulic fractures. Before putting the well on flowback, the induced fractures are occupied by the compressed fracturing fluid. Therefore, analyzing the produced fracturing fluid should in principle be able to characterize the induced fractures, and complement the production data analysis.
We develop a rate transient model for describing the fracturing fluid flowback. We also make various diagnostic plots for understanding the flowback behavior of three fractured horizontal wells. The diagnostic plots indicate three separate flowback regions. In the first region, water production dominates while in the third region hydrocarbon production dominates. In the second region, water production drops and hydrocarbon production ramps up. In general, we observe a linear relationship between rate normalized pressure (RNP) and material balance time (MBT) for the three regions. However, the proposed model can only describe the response of the first region. We successfully determine the hydraulic fracture permeability by history matching the early time flowback data. We conclude that the flowback analysis can complement the production data analysis for a comprehensive fracture characterization. The presented study encourages the industry to start careful measurement of the rate and pressure data immediately after putting the well on hydraulic fracture flowback.
Simultaneous Estimation of Relative Permeability and Capillary Pressure for Tight Formations from Displacement Experiments
Authors: Zhang Yin , Song Chengyao , Zheng Sixu , Yang Daoyong 
Published: October 2012

Abstract
An ensemble-based technique has been developed and successfully applied to simultaneously estimate the relative permeability and capillary pressure in a tight formation by history matching the conventional measurement data from displacement experiments. Relative permeability and capillary pressure curves are represented by the power-law model. Then, the to-be-estimated coefficients of the power-law model are tuned automatically and finally determined once the measurement data have been assimilated completely and history matched. This new technique has been validated by a synthetic coreflooding experiment and then extended to a real coreflooding experiment. Simultaneous estimation of relative permeability and capillary pressure has been found to improve, while standard deviation of the estimated coefficients is reduced gradually as more measurement data is assimilated. There exists an excellent agreement between both the updated relative permeability and capillary pressure and their corresponding reference values, once all the measurement data are assimilated. The relative permeability can be determined more accurately than the capillary pressure owing to the fact that it is more sensitive to the conventional measurement data. This newly developed technique has good computation efficiency and is suitable for performing uncertainty analysis under the same framework.
Non-Darcy Flow in Shale Nanopores: Do We Have a Final Answer?
Authors: Swami Vivek , Clarkson C. R. , Settari A. (Tony) 
Published: October 2012

Abstract
Many shale gas and ultra-low permeability tight gas reservoirs can have matrix permeability values in the range of tens to hundreds of nanodarcies. The ultra-fine pore structure of these rocks can cause violation of the basic assumptions behind usage of Darcy’s law. Depending on a combination of P-T conditions, pore structure and gas properties, non-Darcy flow mechanisms such as Knudsen diffusion and/or gas slippage effects could be important. Quantifying these effects is critical for correcting laboratory permeability measurements to obtain true (intrinsic) matrix permeability; several authors have also noted that corrections for these effects may also be important when analyzing field data. In order to make corrections for non-Darcy flow, numerous authors have quantified these effects as an apparent permeability that changes as a function of Knudsen number or gas pressure. There are now many correlations available for quantifying apparent permeability changes, but it is not known how much impact they really have on the long term production performance of shale gas wells.
In this work, we summarize the various methods for quantifying non-Darcy flow in unconventional gas reservoirs, and compare the apparent permeability and slippage factor predictions for all the models we have compiled. For determining the impact of the model predictions on well performance, we incorporate the apparent permeability predictions of each model into a numerical simulator, and compare rate-time and cumulative gas-time forecasts for each scenario. The importance of dual porosity (which is usually assumed necessary for shale gas) is also examined. The results of this work are important in several aspects. First, the differences between various formulations of the apparent matrix permeability in shales are illustrated. Secondly, the impact of non-Darcy effects on history matching and recovery forecasting is demonstrated. Finally, it is shown that there may not be a need for dual porosity modeling in certain cases.
The results of this study will be important to professionals involved in laboratory measurement of matrix permeability in unconventional gas reservoirs, modeling well performance, and forecasting shale gas recovery.
Hydraulic Fracture Containment in the Bakken With a Synthetic Polymer Water Based Fracture Fluid
Authors: Hassen Barry , Zotskine Youssouf , Gulewicz Dale 
Published: October 2012

Abstract
Hydraulic fracturing in the Bakken oil reservoir on the Canadian side of the Williston basin involves a risk of connection to the overlying water bearing formations. The Bakken reservoir is a tight dolomitic siltstone which requires multiple stage hydraulic fracturing in horizontal wells to achieve economic oil production rates. Within ten to fifty meters above the Bakken reservoir there often is a higher permeability water bearing interval in the Lodgepole limestone formation. If hydraulic fractures connect to the higher permeability interval in the Lodgepole, then water production and associated handling costs would greatly increase. Any loss of fracture fluid and proppant to the Lodgepole could also reduce effective fracture length within the Bakken and subsequently lead to lower oil production rates. To minimize the potential negative impact of partial hydraulic fracture growth out of zone, several strategies have been used. Some of these strategies include reduction of pump rate, slurry volume and fluid viscosity. Minimizing fluid viscosity without significantly reducing proppant suspension can be a challenge. To address this issue, a unique synthetic polymer water based fluid system with excellent proppant suspension characteristics has been field tested. This system has a viscosity between that of linear gel and typical crosslinked systems and has a unique breaking process. This fluid system has been used in multiple Bakken wells for over one year and field production results will be reviewed to demonstrate the effectiveness of the combined strategies in reducing water/oil ratios. The impact on oil production rates will also be reviewed. The paper will furthermore outline several challenges with deployment in the field. Fracture geometry simulation will be used to demonstrate the expected sensitivity of fracture containment to fracture fluid viscosity and pump rate.
An Investigation of Vertical and Lateral Communication in an Unconventional Oil Reservoir Using Geochemistry and Reservoir Simulation
Authors: Rasdi Faisal , Salman Ahmad , Adams Doyle A. , Sofer Zvi 
Published: October 2012

Abstract
Vertical and horizontal inter-well communication in unconventional reservoirs remains a major uncertainty. This paper presents the results of geochemical analyses performed on several wells in the Bakken and Three Forks unconventional oil reservoirs. Geochemical analyses performed on oil extracted from core, oil sampled while drilling, and oil produced after stimulation indicate that the geochemical signatures of the Bakken and Three Forks Formations are different and unique to its respective stratigraphic units. Using unique geochemical signatures, this study developed a procedure for identifying the production of mixed oils and the relative contribution from each contributing startigraphic units.
To further investigate vertical communication a detailed geologic model was constructed using core and outcrop data. The model was simulated and history matched to estimate contribution from adjacent layers. Various scenarios were simulated to understand the probability of communication. Analyses suggest that vertically adjacent layers contribute to production as predicted by the reservoir model and measured by the geochemical signature of the oil.
This paper demonstrates (a) contribution from vertically adjacent formations can be significant, (b) geochemistry may be utilized to quantify vertical drainage, and (c) quantification of contribution from offset layers helped to constrain a reservoir simulation history match. Results from this study have facilitated the assessment of the degree of vertical communication across various flow units, which is the key to an efficient reservoir development.
Forecasting, Sensitivity and Economic Analysis of Hydrocarbon Production from Shale Plays Using Artificial Intelligence & Data Mining
Authors: Esmaili S. , Kalantari-Dahaghi A. , Mohaghegh S. D. 
Published: October 2012

Abstract
Our understanding of the complexities of the flow mechanism in Shale plays has not kept up with our industry’s interest in these prolific and hydrocarbon rich formations. Furthermore, massive multi-cluster, multi-stage hydraulic fractures, that have proven to be essential for economic recovery from Shale plays, have significantly increased the complexity of the flow behavior and consequently have made the modeling efforts more challenging.
In this paper, the application of a recently developed AI (Artificial Intelligence)-based reservoir modeling approach on Marcellus Shale is presented. In this approach, data mining and pattern recognition techniques were used to initiate modeling of the hydrocarbon production (dray gas and condensate) from Marcellus Shale. Instead of imposing our understanding of flow and transport in shale gas media, which is a very complex and non-linear system, we allow the production history, reservoir characteristics, and hydraulic fracturing data and operational constraint to force their will on our model and determine its behavior.
In this work, the full-field history matching process was performed on a Marcellus shale asset including 135 wells with multiple pads and different landing targets. The full field AI-based Marcellus Shale model then used for forecasting the future well/reservoir performance to assist in planning field development strategies. The goodness of match quality is self-evident, thereby validating this modeling approach. Nevertheless, to examine the model validity in the forecasting mode, the field data was partially matched and then attempted forecasting. Taking validation one-step further, the production performance of a recently drilled well, which was completely blind to the model (was not involved during training and initial validation), was predicted and compared with actual field measurement.
Furthermore, sensitivity and economic analysis are performed in order to identify the impact of different reservoir descriptions (e.g. different reservoir characteristics, stimulation and completion factors) and rank the impact of above-mentioned parameters on the Net Present Value (NPV) of investing on gas wells producing from Marcellus Shale.
Case Studies Suggest Heterogeneity is a Favorable Characteristic of Shale Gas Reservoirs
Authors: Li Jun , Guo Boyun , Ling Kegang 
Published: October 2012

Abstract
Natural gas exploration and production from shale gas formations have gained great momentum throughout the world in the last decade. Producing natural gas from shale is challenging because of the high uncertainty in well productivity. It is imperative to investigate and understand the gas flow mechanism in the shale gas formations. This paper investigates the shale gas production mechanism based on field case studies.
Guo et al.’s analytical well productivity model was employed in this work for analyzing gas productivity of a shale gas well in the Fayetteville Shale basin. Model analyses indicate that shale heterogeneity (natural fractures/custers and organics spots) is a favorable characteristics of shale gas reservoirs because they contribute to the initial and long-term well productivity. Shale gas reservoirs without natural fractures/clusters will not produce natural gas at commercial rates even a few hydraulic fractures are created. The intensity of natural fractures/clusters is a key factor affecting the potential of shale gas wells. Hydraulic fractures are useful for intersecting natural fractures/clusters to make well more productive, but it is not necessary to create high-conductivity fractures for this purpose. Shale gas wells should be placed in the areas where high-natural fracture intensity and solid organic material contents are present.
Utilization of Anisotropic Velocity Models in Surface Microseismic Monitoring to Improve Hydraulic Fracturing Event Location Accuracy in Shale Plays
Authors: Neuhausa Carl W. , Remington Christine , Barker William B. , Blair Keith 
Published: October 2012

Abstract
The work presented in this paper focuses on the application of an anisotropic velocity model in determining microseismic event locations from surface-acquired passive seismic data. The Thomsen parameters ε and δ were determined to accurately locate calibration shots to their known location. Hydraulic fracture events where then imaged and compared to their locations derived from processing incorporating an isotropic velocity model.
Velocity models used in the processing of surface microseismic data are in many cases initially derived from sonic logs and subsequently adjusted based on calibration shots (typically perforations or string shots). A scalar shift is usually applied to the velocity model to locate events at depth. Although calibration shots can be located with sufficient accuracy, this method does not directly account for the anisotropic nature of shales. As determined by Thomsen (1986), anisotropy for nearly vertical wave propagation, is mostly governed by the parameter δ, which is "an awkward combination of elastic parameters" (Thomsen, 1986), and appears to be sensitive to the conformity of the contact regions between clay particles, as well as to the extent of disorder in their orientation (Sayers, 2005). However, the importance of ε increases with with an increasing horizontal component of the propagation path.
Event location accuracy in surface microseismic monitoring is known to be fairly robust using the regularly assumed isotropic velocity model (Thornton, 2011), but this can be further improved in some instances by determining ε and δ to account for velocity anisotropy (Eisner et al., 2011). When compared directly to calibration shot locations derived with an isotropic velocity model, we showed that the absolute average error in calibration shot positioning in all directions was improved by almost 30% and hypocenter events from the hydraulic fracturing treatment depicted a more dense and confined zone of microseismic activity.
Drill Cuttings and Characterization of Tight Gas Reservoirs – An Example from the Nikanassin Fm. in the Deep Basin of Alberta
Authors: Solano N. A. , Clarkson C. R. , Krause F. F. , Lenormand R. , Barclay J. E. , Aguilera R. 
Published: October 2012

Abstract
Estimation of rock properties from drill cuttings is proving valuable in the geologic description of tight gas strata. The characterization scheme includes an integrated analysis of detrital and authigenic mineralogy, pore geometry, and flow and storage capacity using drill cuttings samples calibrated with a limited amount of core data. This methodology has been successfully applied to characterize the fine-grained siliciclastic, shallow marine Nikanassin Formation in the Deep Basin of Alberta.
This workflow is particularly useful for the characterization of undercored low permeability hydrocarbon-bearing intervals from both new and legacy wells. Macroscopic description of drill cuttings samples, coupled with petrographic analysis performed on custom made multi-sample thin sections from the same samples allows a direct correlation between these two observations. The principal detrital and authigenic components are also investigated through microprobe analysis and SEM imaging of selected samples. Porosity values and dominant pore geometries are estimated using laboratory measurements and thin section image analysis. Finally, permeability values are measured using the Liquid Pressure Pulse methodology on drill cutting samples.
Porosity and permeability of the analyzed samples ranges between 2–13%, and 0.01–0.25 mD, respectively. Porosity values from drill cuttings samples are found to be slightly higher than routine core analysis measurements, which in turn usually have higher values than porosity estimated from thin sections. A high degree of reproducibility was confirmed for the porosity values obtained from the saturation method on drill cutting-sized samples, with resultant values comparing very well with measurements from standard nuclear magnetic resonance on the same samples. Reservoir quality within the analyzed samples is highly affected by quartz overgrowth and subsequent carbonate cement, with the former increasing with depth. Compared to the dominant microporosity domain, remnant intergranular porosity significantly enhances the permeability of the samples.
This workflow represents an inexpensive yet comprehensive interpretation tool specially targeted to improve the geological understanding of potential by-passed tight gas formations, which usually lack representative cored intervals. In addition, economic returns can be highly optimized by partial replacement of coring programs by appropriate sampling and preservation of drill cuttings samples in new wells.
A New Foam Rheology Model for Shale-Gas Foam Fracturing Applications
Authors: Edrisi A. R. , Kam S. I. 
Published: October 2012

Abstract
A rapidly-growing energy demand in recent years has made shale gas more attractive than ever. Although shale-gas formations contain a large amount of hydrocarbons, their low-permeability characteristics have been a major impediment to economic development of the fields. Once properly designed, foam fracturing has advantages over the conventional hydraulic fracturing – for example, by using less water, it works better for water-sensitive shale-gas reservoirs; a smaller quantity of water involved makes the fracturing job more environment-friendly due to the reduced amount of chemical additives; and it offers a superior capability to carry and distribute solid proppants over the newly-created factures. In spite of its unique advantages, optimum foam fracturing treatment requires a good understanding of foam rheology.
A series of recent experimental studies revealed that foam flow can be represented by two distinct flow regimes in general: low-quality regime showing stable plug-flow pattern, and high-quality regime showing unstable slug-flow pattern. This study, for the first time, presents how to develop a comprehensive foam model that can handle a variety of bubble-size distributions and flow patterns by using two-flow-regime concept for fracturing.
Analyzing experimental data of surfactant foams and polymer-added foams shows that (i) in the low-quality regime, foam rheology is governed by bubble slippage at the wall with no significant change in its fine foam texture and (ii) in the high-quality regime, foam rheology is governed by the relative size of free-gas segment to fine-textured foam-slug segment. By using these governing mechanisms, this new foam model successfully reproduces foam flow characteristics as observed in the experiments, including almost horizontal pressure contours in the low-quality regime and inclined pressure contours in the high-quality regimes. Although the model is built with a power-law fluid model, the same procedure can be taken for Bingham-plastic or yield-power-law fluids.
Using Production Data to Generate P10, P50, and P90 Type-Curves for Shale Gas Prospect
Authors: Williams-Kovacs J. D. , Clarkson C. R. 
Published: October 2012

Abstract
As a result of improved technology and declining conventional gas reserves, shale gas (SG) and other tight-rock reservoirs have emerged as significant sources of oil and natural gas.
Since late-2008 natural gas prices have been depressed in North America as a result of oversupply with unmatched demand. Suppressed commodity pricing has made unconventional gas production uneconomic or marginally economic in many areas, which places a greater emphasis on prospect analysis and careful selection of areas of investigation and drilling locations.
This paper discusses a new tool that was developed specifically for generating probabilistic (P10, P50 and P90)1 type curves for shale plays, based on a series of input production wells, which can be used in the early stages of the stochastic analysis of shale gas prospects. This technique will be discussed in detail and a sample case will be given to demonstrate the methodology for a simulated prospect. This methodology combines the use of a cumulative probability distribution (cumulative distribution function – CDF) for a key distribution parameter (i.e. one year cumulative gas produced) with flowing material balance (FMB) to estimate original gas-in-place (OGIP) and drainage area and the square root of time plot analysis to estimate linear flow potential (kmAcm). The results of these analysis techniques are then combined with estimates of other key PVT and reservoir parameters to generate a type curve for each of the probability levels of interest. These type curves can then be used in the stochastic analysis of SG plays using a methodology such as that presented by Williams-Kovacs and Clarkson (2011) for unconventional prospect screening.