bluuebunny/crossref_metadata_2025_split huggingface dataset:
In-Situ and Induced Stresses in the Development of Unconventional Resources
Authors: Han H. , Higgins-Borchardt S. , Mata D. , Gonzales V. 
Published: September 2014

Abstract
Multistage hydraulic fracture stimulation of horizontal wells often results in asymmetric hydraulic fractures, which are suboptimal for draining reservoirs. Field observations suggest that hydraulic fractures grow further than expected toward, and sometimes up to and beyond, adjacent producing wells. Such interference from nearby wells is of increasing importance in densely drilled unconventional reservoirs, where hydraulic fracturing is common. Eventually, the underlying mechanism needs to be factored into well spacing plans and hydraulic fracture treatment designs, which can either mitigate the undesired consequences of the nonvirgin conditions, or take advantage of them.
An integrated approach has been developed to quantify depletion-induced stresses. In this approach, a three-dimensional (3D) Mechanical Earth Model (MEM) is constructed using the finite-element method to initialize the in-situ stresses. Coupled simulation between the dynamic reservoir model and the geomechanical model is used to quantify stress variation, induced by pressure depletion of the parent well. The altered stress profile is then used as input to a hydraulic fracture design.
The methodology has been applied to an unconventional resource play in the Williston Basin in North America. In this example, three adjacent horizontal wells were hydraulically fractured and put on production sequentially within four years. The analysis indicated that the minimum horizontal stress decreased in the area between a newly drilled well and the nearby producing well; whereas the area on the opposite side of the new well showed no obvious stress variations. Formations above and below the depletion zone experienced an increase of minimum horizontal stress as a balance effect of the finite-element calculation. Fracture modeling using the depletion-induced stresses showed that the effective half-length of the fracture directed toward the depleted well can extend up to two times the length of the hydaulic fracture in the opposite direction.
Building Meaningful Upstream Representations for the LNG Supply Chain
Authors: Kirk Graham , Wieclawek Kristian , Cameron P. 
Published: September 2014

Abstract
Over the last decade, breakthroughs in new oil and gas technologies have helped access untapped resources and allowed for their economic production. Through horizontal drilling and new completion techniques, gas trapped in low permeability tight shales is now accessible. Higher world gas prices have made gas liquefaction economic, facilitating transport of liquefied natural gas (LNG) to overseas markets. Technology, coupled with supply and demand, has initiated a new generation of mega-projects around the globe. These projects encompass the entire supply chain, from field development to pipelines feeding the LNG facilities, to shipping the product to market. As the global market for natural gas continues to grow, there is tremendous investment potential. However, due to complexities involved, accurate modeling is critical to understand the best investment strategy and to minimize risk.
This paper will explore the intricacies involved in modeling upstream field development and the scenarios required to provide reasonable estimates of the upstream asset that will feed the rest of the LNG chain. We will look at the entire upstream asset from the investor's point of view, including investment required, growth potential, and long-term sustainability. We will compare how different decisions in field selection and development rate impact overall value. This paper will highlight the importance of using technical expertise, high quality data and specialized modeling software to produce a meaningful representation of an upstream development plan.
A Flowback-Guided Approach for Production Data Analysis in Tight Reservoirs
Authors: Ezulike O. D. , Dehghanpour H. , Virues C. J. , Hawkes R. V. 
Published: September 2014

Abstract
One key limitation of conventional production data analysis (PDA) is non-uniqueness of solution. This can cause huge uncertainty in reservoir parameter estimates and hydrocarbon forecasts. Hence, there is need for an alternative approach to PDA. This paper tackles this issue using flowback data analysis (FDA) as a constraint to guide PDA. We recently extended the existing linear dual-porosity model (DPM) to develop a flowback analysis model (FAM). Here, we intend to i) test the accuracy of FAM to predict gas production in the field, and ii) investigate how the results from its application on flowback data could reduce the uncertainty associated with conventional PDA.
This study applies FAM to history match 2-phase flowback data from three multifractured shale-gas wells completed in the Horn River Basin. The history match estimatesFAM estimates effective half-length and initial gas-volume in hydraulic-fractures before flowback. It is also used to forecasts post-flowback gas production. This forecast is verified by comparing it actual post-flowback production data. An independent single-phase PDA on post-flowback production data from the same shale-gas wells overestimates hydraulic fracture(HF) half-lengths compared to the FAM history-match results. This could be a result of the presence of water plugged secondary fractures with negligible communication interface with the hydraulic fractures during flowback. The interface significantly increases during post-flowback production periods as water gives way to gas from the matrix. One key result of this study is that HF half-lengths from PDA could significantly differ from those from post-flowback PDA.
It is more appropriate to interpret both flowback and production data using a single multiphase model. FAM is an example of such models that captures the "necessary" physics for both flowback and production operations. PDA without considering flowback data could lead to inaccurate results. This study shows how to perform a robust flowback-data-analysis that complements PDA for comprehensive fracture/reservoir characterization. These results encourage the industry to start careful and accurate measurement of rate + pressure immediately after opening wells for flowback.
Well Spacing Optimization in Eagle Ford
Authors: Lalehrokh F. , Bouma J. 
Published: September 2014

Abstract
Due to the ultra-low permeability in shale reservoirs, hydraulic fractures are developed to provide secondary permeability to increase production in horizontal wells. Well spacing is a key factor in maximizing the net present value (NPV) of a shale reservoir utilizing horizontally fractured wells. The dilemma is that the wells should be spaced close enough together to maximize the total stimulated area and drain the entire section in a timely manner, yet on the other hand, far enough from each other to minimize the chance of fracture hits by offset wells or overlapping the drainage area of a nearby well to avoid over-capitalization.
The Eagle Ford shale has become a major resource play in North America and has become the focus of exploration and drilling activity for several oil and gas operators. Numerous studies have been performed to optimize well placement in shale gas reservoirs but unfortunately few have been conducted in reservoirs with multi-phase flow of oil and gas. The purpose of this paper is to find a balance between maximizing the stimulated area without over-capitalizing the play. Three distinctively different, real scenarios have been selected to study the effect of well spacing on estimated ultimate recovery (EUR) and ultimately on NPV. Also, a sensitivity study has been performed to analyze the effect of reservoir permeability and fracture half-length on optimal well spacing. The dimensionless metric, discounted profitability index (DPI), is also used in conjunction with NPV to ensure that while trying to maximize the NPV of the asset, the incremental investment decision still meets corporate economic thresholds and competes for capital within the portfolio.
Based on the reservoir simulation and economic analysis, well spacing of 330 ft and 400 ft maximizes the NPV of a black oil Eagle Ford reservoir by assuming 50 nD reservoir permeability and fracture half-length of 100 and 150 ft, respectively. Well spacing of between 400ft and 450 ft maximizes the NPV in the retrograde gas case study. Detailed results are also provided to illustrate the effect of fracture half-length, reservoir permeability as well as oil price variation.
Improvement in Permeability Models for Unconventional Gas Reservoirs and Model Selection Using Statistical Analysis
Authors: Haghshenas B. , Clarkson C. R. , Bergerson J. , Chen S. , Pan Z. 
Published: September 2014

Abstract
Unconventional gas reservoirs have complex storage and transport properties that are difficult to characterize and are dynamic. The large internal surface area of nano-scale organic pores gives them the capability to store adsorbed gas along with free gas, with the amount of free gas storage changing as a function of adsorption/desorption. Further, diffusion and slippage mechanisms compete with compression and possibly matrix shrinkage effects to alter absolute permeability of the organic matter pores. An additional factor controlling permeability change, which has not been previously considered, is the change of effective radius of organic matter pores as a function of adsorption/desorption. A statistical study is required to fully explore the overall effect of the above mentioned parameters on unconventional gas well production performance, along with other properties such as total carbon content, pore connectivity configuration, adsorption capacity, pore size distribution, and natural fracture intensity.
In this study we investigate two sets of matrix pore sizes thought to represent a reasonable range observed in unconventional gas reservoirs. Pore size affects the interaction between the gas molecules and pore walls and results in a distribution of adsorbed phase thickness. Therefore, the adsorbed layer modifies the effective hydraulic radius for flow of gas which in turn alters the effective permeability to the gas phase in organic matter pores. This complexity can be captured by combining the simplified local density model and apparent permeability approaches. The contribution of compression and matrix shrinkage to fracture permeability change with pressure is also investigated and compared to changes in apparent permeability in the matrix caused by diffusion and slippage mechanisms.
A commercial reservoir simulator is used to study the effects of pore size and pore size alteration, and consequent permeability changes, on unconventional gas well performance. A screening statistical method is used to quantify the relative importance of each factor.
The results of this study will help the engineers evaluate the relative importance of all of the permeability-altering processes that can affect unconventional gas well performance, and make appropriate simplifying assumptions. This will enable them to prioritize history matching parameters for real production data analyses and forecasting, which in turn decreases the time required for a complete field simulation study.
Understanding the Origin of Flowback Salts: A Laboratory and Field Study
Authors: Zolfaghari Sharak Ashkan , Noel Mike , Dehghanpour Hassan , Bearinger Doug 
Published: September 2014

Abstract
Several past studies have focused on the saline flowback water to evaluate the hydraulic fracturing operations. The origin of the salts in the flowback water is important for the assessment of the flowback process. In this study, laboratory and field analyses are performed to provide a better understanding about the origin of the flowback salts.
The field study analyzes the total salt concentration (salinity) and ion concentration data measured during the flowback process for the Muskwa (Mu), Otter-Park (OP), and Evie (Ev) formations. The concentration profiles of both the barium and chloride during the flowback process, whereas the iron concentration declines after experiencing an initial increase.
The laboratory study encompasses contact angle, XRD, imbibition, individual ion concentration, surface element, and adsorption isotherm experiments for samples from the OP and Ev formations. To investigate the effects of fluid-rock interface area on the liquid uptake and diffusion rate of individual ions, a series of imbibition experiments are carried out for different values of surface to volume ratios (specific surface or "Asp"). The electrical conductivity and individual ion concentrations are measured during the imbibition process. XRD data is analyzed to determine the mineralogy of the samples. SEM-EDX analysis is performed to determine the distribution of the elements on fresh break and natural fracture surfaces of the samples (in addition to a sample from the Lower Keg (LK) formation). Finally, since both ion transfer and water adsorption processes occur during the imbibition experiment, an adsorption isotherm experiment is carried out to prevent the ion transfer into/out of the rock in order to solely study the water adsorption process. The laboratory results show that barium is mainly concentrated in the natural fractures; and therefore the shape of the barium concentration profile in the flowback water maybe an indication of the complexity of the fracture network.
Understanding the Optimum Fracture Conductivity for Naturally Fractured Shale and Tight Reservoirs
Authors: Gu Ming , Kulkarni Pandurang , Rafiee Mehdi , Ivarrud Endre , Mohanty Kishore 
Published: September 2014

Abstract
With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received a greater attention in recent years. The post-frac productivity of such low-permeability reservoirs is largely determined by the matrix-fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that the production increases with the proppant amount injected.
This paper presents an approach to assess the optimum proppant amount injected by determining the post-frac conductivity. First, using three-dimensional finite difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete grid blocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural fracture properties (intensity and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range 20-1000 nD, natural fractures increase the short-term critical conductivity but decrease the medium to long-term ones. The paper also evaluates the influence of water production, cluster spacing, and BHP flowing pressure on the critical conductivity.
This study demonstrates that Agarwal type curves based on linear flow are not appropriate for naturally fractured reservoirs and lead to errors in estimation of critical conductivity. The results of this study can be useful for selecting the type and amount of proppant for stimulation of unconventional reservoirs.
Interrelationship of Weak Organic Acids, Bases, pH and HPLC Analysis Method in Produced Waters
Authors: Weissenberger Markus C. , Dhillon Sukhmeet 
Published: September 2014

Abstract
Weak Organic acids, such as acetic or formic acid, are ubiquitous in produced waters from petroleum-producing basins. Although the absolute concentrations of individual short-chain acids vary over many orders of magnitude the concentration can reach up to 1000 mg/L or more. It is known that weak organic acids influence the pH and alkalinity of a given water significantly, because they act as a buffer. Therefore the hydration and gelation of Guar based fracturing fluids could be affected. As the industry trend is to use more produced water as a base fluid for fracturing fluids, it is of interest to measure the concentration of different weak organic acids in produced waters and determine their influence on the hydration and gelation of fracturing fluids.
The chosen measurement system was a HPLC system with a standard hydrophobic C18 column and sodium dihydrogen phosphate as mobile phase. The method was calibrated for formic acid, acetic acid, propionic acid and butyric acid, as these for weak organic acids are the most common naturally occurring species. With this analytical method we were able to detect and determine the weak organic acid concentration in different produced waters up to a few mg/L. The high concentration of sodium and chloride ions could cause a matrix problem and hinder the correct analysis. In order to eliminate this influence the reversed-phase method was chosen. By this it was possible to detect also low concentrations of organic acids in high salinity produced waters.
Integrating Active and Passive Seismic Data to Better Predict Hydraulic Fracturing
Authors: Castillo G. , Chesser K. , Bouziat A. , Oliver G. , Ly C. V. , Kuo L. , Bathellier E. 
Published: September 2014

Abstract
Although drilling has slowed substantially from its peak in 2010, steadily improving natural gas prices coupled with the promise of demand from liquefied natural gas and gas to liquids facilities have renewed interest in the prolific Haynesville shale gas play in NW Louisiana. A consensus of opinion among operators in the field will agree that only a fraction of the Haynesville potential has been developed to date. As is the case in most shale plays, production from wells has been highly variable, leading to the use of 3D seismic reservoir characterization studies for the determination of sweet spots, well placement and completion strategies where seismic anisotropy has been proven to be an important factor in understanding the shale plays. This paper illustrates a workflow (Figure 1) integrating reservoir and geomechanical properties obtained from pre-stack seismic inversion and incorporating stress and fracture information extracted from azimuthal analysis of the seismic data. Eight wells in the area targeting the Haynesville and mid-Bossier reservoirs were used for calibration of surface seismic measurements of reservoir and geomechanical properties. A variety of seismically derived attributes are used to estimate production potential in the field. This paper shows the application of global azimuthal inversion, a technology for extracting the azimuthal anisotropy. Above all, the workflow makes quantitative use of microseismic and SEM (Scanning Electron Microscope) derived mineralogy data to validate the seismic-derived attributes.
Figure 1 Integrated geoscience workflow for a shale play, incorporating numerous discipline to high-grade the survey area to identify ‘sweet spots’ and optimize drilling locations and completions.
Multiphase Rate Transient Analysis in Unconventional Reservoirs: Theory and Applications
Authors: Eker Ilkay , Kurtoglu Basak , Kazemi Hossein 
Published: September 2014

Abstract
In unconventional reservoirs, production data is generally analyzed using rate transient techniques based on single-phase linear flow models. Such linear flow models use rate-normalized pressure, which is pressure drop divided by reservoir flow rate versus square root of time. In practice, the well fluid production includes water, oil and gas. The oil can be light oil, volatile oil, and gas-condensate as in Bakken, Eagle Ford, and Barnett. Thus, single-phase analysis needs modification to account for production of fluid mixtures.
This paper presents a new approach to analyze multi-phase flow in single and dual-porosity models of unconventional reservoirs. In addition to oil, gas and formation brine, the method accounts for gas condensate production, and the flowback of the injected hydraulic fracturing fluid. Overall, the proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods.
The paper includes a workflow and several diagnostic plots for light oils to gas condensates in unconventional reservoirs. Flow rate transient data from two Bakken and Eagle Ford wells will be presented to demonstrate the usefulness of our models. In addition to the mathematical analysis of flow rate and pressure data, we will explain well stimulation configuration and fluid lift methods influence the flow rate history of the Bakken and Eagle Ford wells.
Influence of Friction Reducer on Scale Inhibitor Performance and Scaling Tendency in Slickwater Fracturing
Authors: Ozuruigbo Chioma Q. , Fan Chunfang 
Published: September 2014

Abstract
Slickwater fracturing generally contains approximately 95% sand and 5% other production chemicals, such as scale inhibitor (SI), friction reducers (FRs), surfactants, etc. It is important to study the effect of FRs on SI inhibition performance because of the interactions between both chemicals when pumped together during slickwater fracturing treatments.
Most FRs used in the industry are usually a combination of polyacrylamide- (PAM-) based polymers, acrylic acids, and acrylamido-methyl-propane sulfonate polymer (AMPS) copolymers, which readily interact with components of SIs. This paper examines the effect of FRs on SI performance and the scaling tendency of produced water. Conclusions drawn regarding static bottle tests, dynamic tube blocking tests, and inductively coupled plasma (ICP) analysis of data from a series of performance tests under reservoir conditions are discussed. The laboratory methods used to qualify and measure the performance of the SIs during these tests are also discussed.
Tests were conducted using produced water brine from the Rulison field in Colorado. The testing results demonstrated diminished performance of SI when combined with a FR. Five SIs of different chemistries were run to observe the resulting performance effects of the SIs with and without FRs. Static bottle tests conducted using only SIs exhibited a minimum effective concentration (MEC) of ≥ 20 to 50 ppm for complete scale control. With the addition of 0.25 gpt of FRs, the MEC increased to approximately 100 to 250 ppm for the different SIs based on ICP elemental analysis data. Additionally, the test results demonstrate that a denser amount of solid precipitation occurs with the combination of both FR and SI. Results obtained from this study provide more awareness to the resulting effects of combining these fracturing fluids during slickwater fracturing. This work provides insight into making proper scale control decisions, particularly when SIs and FR are pumped simultaneously, thereby helping reduce damage.