bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure Transient Analyses of Short and Long Duration Well Tests in Unconventional Reservoirs
Authors: Kurtoglu Basak , Torcuk Mehmet A. , Kazemi Hossein 
Published: October 2012

Abstract
Horizontal wells are used in unconventional oil and gas reservoirs to increase production by creating large drainage surface areas and contact volumes. Production is further improved by applying hydraulic fracture stimulation in horizontal wells. Hydraulic fracturing increases well productivity via the large drainage surface of the fracture and by rejuvenating existing natural fractures as well as creating new fractures in the vicinity of the wellbore. The affected reservoir volume is known as the stimulated reservoir volume (SRV) which includes a complex flow network that creates different flow regimes.
We will present several short and long pressure transient tests conducted in vertical and horizontal wells, to determine critical formation properties of the low-permeability, dual-porosity Middle Bakken and Three Forks reservoirs. Pressure transient test data were obtained via permanent downhole pressure gauges. The bilinear and linear flow regimes of the pressure buildup tests are the focus of the analyses. For this, we have presented an analytical solution using numerical inverse Laplace transform as well as closed-form approximate solutions.
Flow rate transient analysis of long-duration production data were also conducted to compare with the results of the pressure transient analyses. All tests indicated that the field measured permeability is several orders of magnitude greater than permeability measured on core plugs. This indicates the presence of a network of interconnected fractures and microfractures in the stimulated near-well regions without which no significant production would result. The details of the well tests and analyses will be presented for engineering applications.
Analytical Model for History Matching and Forecasting Production in Multifrac Composite Systems
Authors: Stalgorova Ekaterina , Mattar Louis 
Published: October 2012

Abstract
This paper presents an analytical model for unconventional reservoirs with multiply-fractured horizontal wells. The model is an extension of the "tri-linear flow" solution, but it subdivides the reservoir into five regions instead of three. This enables it to be used for more complex reservoirs. Accordingly, the model can simulate a fracture that is surrounded by a stimulated region of limited extent (branch-fracturing), while the remaining reservoir is un-stimulated. In addition to modeling flow within the fracture and flow within the stimulated region, the model takes into account flow from the surrounding un-stimulated region, both parallel to and perpendicular to the fracture.
The model can be used to simulate the flow in tight reservoirs with multi-frac horizontal wells. In many cases, the fractures do not have a simple bi-wing shape, but are branched. This effectively creates regions of higher permeability around each fracture, which obviously affect the production performance significantly. However, in many tight reservoirs, in spite of their low permeability, the surrounding un-stimulated region can also be a significant contributor to long-term production. The Five-Region Model accounts for this contribution. Thus it is particularly valuable when generating production forecasts for reserves evaluation.
The model was validated by comparing its results against numerical simulation. We found that analytical and numerical results are in good agreement only when the geometry of the system falls within certain limitations. However these limitations are met in most cases of interest. Therefore the model is useful for practical engineering purposes.
Study of 2-D and 3-D Hydraulic Fractures with Non-Uniform Conductivity and Geometry Using Source and Sink Function Methods
Authors: Xiao Lei , Zhao Gang 
Published: October 2012

Abstract
During hydraulic fracturing process, different hydraulic loading and stress status of formations result in hydraulic fractures with various geometries and properties. Several propagation models including PKN and KGD have been widely applied in fracturing design and implementation. However, in the process of post-stimulation modeling, fractures are usually simplified with uniform geometries and conductivity distribution; therefore the effects of actual fracture geometry and proppant properties on the well transient pressure and production performance remain unclear. This study intends to comprehensively study the fractured wells with 2-D and 3-D non-uniform geometry and conductivity distribution.
In the development of shale gas reservoirs and tight oil formations, horizontal well multistage fracturing is the key technology. The modeling results presented in this paper can help offer valuable information of reservoir properties, evaluate the conductivity distribution of propped fractures, simulate more realistic fracture configurations, and help optimize fracture treatment process and fractured wells’ performances with improved accuracy.
A semi-analytical approach coupling fluid flow in reservoir and fractures existed in more realistic shape with non-uniform conductivity distribution has been developed to obtain well transient pressure and production responses. Source and sink function method is utilized to solve unsteady state flow problems of fluid flowing from reservoir to non-uniform fractures with geometries that are well defined in PKN, KGD and other generally ideal models. The effect of fracture conductivity with linear and stepwise distribution, and elliptic fracture shape variations has been investigated. Comparison study has been highlighted to illustrate effects of fracture geometry and conductivity distributions. Realistic hydraulic fractured wells with non-uniform fracture geometry and conductivity have been studied to showcase a consistent workflow of entering fracture properties from hydraulic fracturing models and outputting fractured well performance prediction in post-stimulation reservoirs.
Instead of assuming pseudo-steady state flow status between reservoir and fracture, unsteady state flow problems related to non-uniform fracture geometric have been solved in a semi-analytical manner with solution of near analytical accuracy. More realistic fracture geometries estimated from fracture propagation models can be entered into post-stimulation models without idealized simplification; thus the gap between fracture propagation and post-stimulation modeling has been fulfilled.
Determination of Fracture Conductivity in Tight Formations with Non-Darcy Flow Behaviour
Authors: Zhang Feng , Yang Daoyong 
Published: October 2012

Abstract
In this paper, a mathematical model has been developed and successfully applied to accurately determine the fracture conductivity in tight formations with non-Darcy flow behaviour. A new non-Darcy flow number is first defined to account for effect of characteristic length in a hydraulic fracture. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments, assuming that there exists unsteady flow between the adjacent segments. The newly developed model has been validated by simplifying it to the traditional Forchheimer (i.e., non-Darcy) model. The pressure response together with its corresponding derivative type curves has been reproduced to examine non-Darcy flow behaviour under different fracture conductivities. Both relative minimum permeability and characteristic length are found to impose a negative impact on fracture conductivity. Compared to relative minimum permeability, characteristic length is a strong function dominating the non-Darcy flow behaviour in the fractures. It is obvious that the fracture conductivity can be accurately determined when non-Darcy flow behaviour in the fracture network is taken into account.
Optimization of CO2 Flooding Schemes for Unlocking Resources from Tight Oil Formations
Authors: Song Chengyao , Yang Daoyong 
Published: October 2012

Abstract
In this paper, techniques have been developed to experimentally and numerically evaluate performance of waterflooding and CO2 flooding for unlocking oil resources from tight formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.081–0.790 mD are used to conduct a series of coreflooding experiments. The performance of four flooding schemes, i.e., waterflooding, near-miscible CO2 flooding, miscible CO2 flooding, and water-alterneating-CO2 flooding, are evaluated by the coreflooding experiments. The continuous CO2 flooding processes under either miscible or near-miscible condition lead to a superior oil recovery performance in comparison with the waterflooding process. Furthermore, the miscible water-alternating-CO2 flooding in tight cores leads to a higher recovery efficiency with less CO2 consumption compared to the continuous CO2 flooding processes. Most importantly, in the miscible water-alternating-CO2 flooding process, it is found that the pressure drop increases rapidly when water is injected, but decreases dramatically when CO2 is injected. This indicates that CO2 injection is able to significantly improve the fluid injectivity in tight formations. In general, the miscible water-alterneating-CO2 flooding process is found to be the most favorable flooding scheme for tight formations in terms of both recovery efficiency and fluid injectivity. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different flooding schemes. There exists a generally good agreement between the experimental measurements and simulated results for all the flooding schemes examined. The tuned numerical model is then employed to optimize the production pressure in the continuous CO2 flooding process and the water-alternating-gas (WAG) ratios in the miscible water-alternating-CO2 (CO2-WAG) flooding process, respectively. It is found that the optimum producing pressure in the continuous CO2 flooding process can be set as the minimum miscibility pressure (MMP) of the tight oil sample, while the optimum WAG ratio falls in the range of 4:1 to 8:1.
The Optimal Completion Techniques for Horizontal Gas Wells in the Cadomin Formation, Northeastern British Columbia
Authors: Yu Shaoyong 
Published: October 2012

Abstract
The Cadomin formation, consisting of conglomerates and sand systems, is an aerially extensive resource play that covers the entire area of northeastern British Columbia, Canada from Township 77, Range 21W6 to Township 68, Range 11W6 in the Elmworth area. It further extends south for hundreds of kilometers along the eastern edge of the Rocky Mountains. The gross pay thickness in the Cadomin formation ranges from 20 ~ 30 meters with porosity ranging from 2 to 7% and matrix permeability ranging from 0.006 mD to 0.7mD, based upon available in-situ Special Core Analysis data.
Due to the low estimated ultimate recovery (EUR) from a typical Cadomin vertical well, there have been more than 300 horizontal wells (including multi-lateral horizontal wells) drilled in this formation since 2001 in order to improve the ultimate recovery. Various completion techniques have been tried in those horizontal wells, which use mainly slick-water bullhead or multi-stages fracturing with or without proppant.
After a review of the public completion data for more than 200 horizontal wells, it was found that as high as two-third of the wells had used only slick-water in either bullhead or multi-stage fracturing; about one-third used slick-water with proppant sand, and the remaining few percent using some other techniques. Detailed analysis of the completion techniques, wells’ EURs and the first 3-month gas production has provided some insights into the following questions: Does fracturing work better with slick-water alone or with proppant?For those wells using slick-water during fracturing, does the amount of water used affecting the final EUR and initial production? Is it true that more water is used better the initial production and the EUR?What are the benefits of using multi-stage fracturing vs. bullhead fracturing?What is the conductivity of the fractures generated by slick-water?
Laboratory Measurement of Sorption Isotherm under Confining Stress with Pore Volume Effects
Authors: Santos Jose M. , Akkutlu I. Yucel 
Published: October 2012

Abstract
For unconventional gas resources such as coal and organic-rich shale, sorbed-phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work a new gas storage measurement technique is proposed combining the porosity and sorption measurements. Because the measurement is done using core plug under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions.
During construction of the sorption isotherm in the laboratory using Boyle’s law setup and a volumetric method, at each pressure step, volume of the sorbed gas taken up by the sample reduces the pore volume of the sample. As a result, the initially determined pore volume at low pressure must be corrected at the beginning and at the end of the pressure step. Also known as Gibbs correction, this correction can be done relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the pore volume could also change due pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret multiple-step laboratory measured pressure data on a graphical domain where the parameter estimation can be done fast and accurately using a straight line. The approach considers both the compressibility and sorbed- phase effects on the pore volume and the sorption parameters.
Experimental storage data of various shale and coal samples with varying total organic content and maturity is used to demonstrate applicability of the analytical method to the measurements. Our results show that the sorption measurements can be done with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
A Case Study to Evaluate Shale Gas Performance Models with Actual Well Production Data
Authors: Yuan Hong , Bhuiyan Mofazzal , Xu Jiafu 
Published: October 2012

Abstract
In this study, three shale gas production models are evaluated against field data from 17 gas wells in four different shale types.
Gas production from unconventional gas reservoirs keeps growing. Although there are many models have been published in the literature, sometimes it is difficult to determine which model to use in predicting the production rate.
Based on a broad literature survey, three shale models were selected to evaluate against field data. The three models are the Duong model, the stretched exponential production decline model and the fracture flow model. The field data are from 17 gas wells in the Barnett shale, the Woodford shale, the Fayetteville shale and the Haynesville shale. Among the 17 wells, there are both dry and wet gas wells, the production history ranges from 3 to 8 years and the maximum monthly production rate ranges from15 MMcf/month to 160 MMcf/month. In the 17 wells, 14 are horizontal and 3 are vertical.
The results of this study can be used as guidelines in choosing shale gas models.
A Model of Canadian Oil and Gas Price Fluctuations - 2012 Update
Authors: Morgan Michael , Herchen L. , Mikalson D. 
Published: October 2012

Abstract
In 2005 a series of statistical calculations were presented for Canadian hydrocarbon prices [1]. There were two main conclusions: long-term historical data indicates that hydrocarbon prices tend to revert back to historical averages, short-term price fluctuations are unpredictable. It is more clear than ever that short-term prices are unpredictable, but this paper will attempt to demonstrate once more that mean reversion should be included in any long-term model.
This paper demonstrates that any discussion of oil and gas prices in Canada must consider inflation. Several different means of adjusting for inflation are presented but all show that Canadian hydrocarbon prices are strongly variable, but mean reverting. This paper also argues that, while convenient, discussing the price of a commodity in terms of only one currency ignores changes in the relative value between currencies and basis differentials. These factors can have significant economic impact.
This paper updates the previous price fluctuation model for prices up to the end of 2012. As before, the model incorporates a random walk with mean reversion that was developed and tuned to fit Canadian hydrocarbon prices. Starting with the current spot price, the model will generate a random but equiprobable prediction of future prices. The model can be used as input into a Monte-Carlo simulation. Alternately, the model can be run multiple times in order to generate "high", "low", and "expected" price predictions.
Water-in-Oil emulsions: Flow in Porous Media and EOR Potential
Authors: Fu Xuebing , Lane Robert H. , Mamora Daulat D. 
Published: October 2012

Abstract
High water content (&gt;50%) water-in-oil (W/O) emulsions have been suggested as a drive fluid for recovery of heavy oil in high permeability reservoirs. High emulsion viscosity can provide sufficient mobility control and its oil-external nature enables a semi-miscible process while displacing crude oil. Initially crude oil itself was suggested as base oil for generating this type of emulsion, and both laboratory experiments and field pilot have demonstrated its high efficiency in recovering heavy crude. Recently used engine oil was suggested as a candidate for generating W/O emulsions for the same purpose, because of its better stability and more favorable viscosity.
In this work a stable emulsion was generated by mixing used engine oil (40%) and brine (60%) under high shear. Then this emulsion was injected into sandstone cores (400 ~ 2400 md, 0.5 or 1 ft in length) at several different rates for periods of several days, to characterize its stability and flow properties while passing through porous media. Small amounts of water breakout were observed in the emulsion effluents. Higher values of water breakout were observed in lower permeability rock, at higher injection rate, and with longer core lengths. The the emulsion was also injected into sand-packed slimtubes (~8000 md) of 3-ft and 6-ft lengths, and less than 1% of free water was observed from the effluents at moderate injection rates, verifying good stability of this emulsion passing through high-permeability porous media. Pressure drops were found to be quite stable at any constant rate of injection for all corefloods, indicating no plug-off effect from the soot particles in the emulsion.
Numerical simulations on emulsion flooding a homogeneous heavy oil reservoir were also conducted by simulating the emulsion as single-phase oil, and the breakdown of emulsion as a co-injection of water together with this oil. Results indicated significant improvement of displacement pattern and oil recovery compared to water flooding.
Importance of the Transition Period to Compound Linear Flow in Unconventional Reservoirs
Authors: Liang P. , Thompson J. M. , Mattar L. 
Published: October 2012

Abstract
Unconventional wells often show linear flow. Rate Transient Analysis (RTA) so far has only concentrated on the primary (early-time) linear flow. However, real production data has often shown more than one transient flow regimes. There are only few studies that focus on analyzing the flow regimes following the primary linear flow. It is not clear how to deal with the transition period as well as the compound (late-time) linear flow. When does the transition start? How long does the transition last? Does compound linear flow always exist? What are the diagnostic values of analyzing the period of transition to compound linear flow? This work answers these questions.
We developed a dimensionless typecurve for a single multi-fractured horizontal well (large inter-well spacing). We investigated the end of the primary linear flow, the duration of the transition and the start of the compound linear flow, for different fracture spacing to fracture half-length ratios. We investigated the effect of skin and superposition time functions. In the end, we proposed a workflow to analyze the production data from multiple-fractured horizontal wells by using the newly developed typecurve, and we presented a field example to show the application of the proposed methodology.
Unstable Displacement: A Missing Factor in Fracturing Fluid Recovery
Authors: Parmar Jaskaran. S. , Dehghanpour Hassan , Kuru Ergun 
Published: October 2012

Abstract
Multi-stage hydraulic fracturing for stimulating tight reservoirs requires a significant volume of fracturing fluid, which is usually water-base. Water recovery is critical due to environmental considerations, water shortage, and formation damage. This work aims at investigating the role of gravity, fingering, and capillarity on water drainage in propped fractures.
We conduct two sets of drainage experiments. In the first set, we investigate the effect of size, size distribution, and wetting properties of proppants on water recovery. In the second set, we conduct drainage experiments in a physical fracture model. In this model, the proppants are packed in the space between two sheets of glass, and the pack is saturated with the fracturing fluid. This simulates the initial condition before opening the well for flowback. For simulating the water drainage in the fractures above, and below the horizontal well, gas is injected from the top and bottom of the cell, respectively.
For gravity-stable tests where water drains downward, the recovery is controlled by capillary forces, which depend on interfacial tension and proppant size. For gravity-unstable tests where water drains upward, the recovery is poor due to the formation of gas fingers. Increasing the injection pressure does not enhance water recovery in the upward displacement. We conclude that a large fraction of non-recovered fracturing fluid resides in the fractures below the horizontal well.