bluuebunny/crossref_metadata_2025_split huggingface dataset:
Examining Our Assumptions – Have Oversimplifications Jeopardized Our Ability to Design Optimal Fracture Treatments?
Authors: Vincent M. C. 
Published: January 2009

Abstract
In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions: –Simple, planar, bi-wing fractures–Completely vertical fractures with perfect connection to the wellbore–Flow capacity that is reasonably described by published conductivity data–Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity)
To forecast production from these fractures, we frequently make the additional assumptions: –Reservoir is laterally homogeneous–Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality)
However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to: –Complicated flow regimes–Complicated geometry–Irregular frac faces–Imperfect proppant distribution–Imperfect hydraulic continuity–Imperfect wellbore-to-fracture connection–Residual gel damage, possibly including complete plugging or fracture occlusion
Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent.
The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
Inflow Performance for a Hydraulic Fracture in a Deviated Well
Authors: Zhang Y. , Ehlig-Economides C. A. , Han G. , Tosic S. , Economides M. J. 
Published: January 2009

Abstract
Wells in high permeability reservoirs are frequently constructed with deviated wellbores completed with a high permeability fracture (HPF). If the deviated well is not drilled perpendicular to the minimum horizontal stress, significant misalignment between the wellbore and the fracture plane is likely to occur. In turn this leads to limited communication between the fracture and the wellbore, resulting in a reduced number of flowing perforations and additional pressure drop. In low permeability reservoirs, even for a misaligned fracture the majority of the flow is through the hydraulic fracture. In contrast in deviated HPF wells a significant flow contribution may be through the gravel pack (GP) perforations that are not connected to the fracture, thus bypassing the fracture. The flow fraction bypassing the fracture depends on the formation permeability and the fracture and gravel pack skins. This paper will show that the conventional inflow performance calculations can not be applied for a HPF well with a misaligned fracture. It is generally incorrect to treat the inflow performance for a deviated HPF well in the same manner as for a vertical well.
This paper provides a semi-analytical model for the flow pattern taking into account both flow to the fracture and flow that bypasses the fracture to the GP wellbore region. The model shows that the limited communication between hydraulic fracture and wellbore has a great impact on the entire flow pattern. A field example with a deviated deepwater well (DW) from the Gulf of Mexico (GOM) will be shown. The flux method will be revised taking into account flow contribution from the GP region, resulting in additional flow perforations but adding more risk for fines movement and skin increase.
Stress Amplification and Arch Dimensions In Proppant Beds Deposited by Waterfracs
Authors: Warpinski N. R. 
Published: January 2009

Abstract
Equations and a procedure have been developed to calculate the excess stress induced on a proppant dune that is deposited by a waterfrac with poor proppant transport characteristics. This method also calculates the dimensions of an arch region that forms above the bed. Stresses on the proppant at the top of such a dune are much greater than usually considered because of the need to support a wide proppant bed and the arch, suggesting that crushing and embedment are likely. The arch region itself is an extremely high conductivity pathway that may provide overall benefit in terms of clean-up and production, but may also aid sand production.
2D Modeling of Hydraulic Fracture Initiating at a Wellbore with or without Microannulus
Authors: Cherny S. G. , Lapin V. N. , Chirkov D. V. , Alekseenko O. P. , Medvedev O. O. 
Published: January 2009

Abstract
The goal of this paper is to investigate the near-wellbore phenomena with respect to fracture initiation. The 2D numerical model was developed, which takes into account the interaction of steel casing, cement, and surrounding rock and allows for a curved path of the fracture. The model incorporates an effective finite-difference numerical method for solving a system of coupled differential equations: 1D equations of power law fluid flow along the fracture trajectory and 2D equations of the linear elasticity for rock massif. The model predicts and evaluates the near-wellbore fracture pinching effect as a function of fracture trajectory, perforation misalignment angle, cement/formation properties, stress contrast, and fracturing fluid parameters.
The model developed has a limitation: it does not take into account the leakoff and pore pressure changes in near-wellbore zone during fracturing treatment. However, we believe that this limitation is not essential as it does not affect the quality of results obtained and can be eliminated easily.
Several different scenarios of fracture initiation and propagation were considered. We modeled the initiation and propagation of the fracture through the narrow channel (microannulus) along cement-rock interface as well as along the misaligned perforation. We also investigated different geometries of microannulus development and made conclusions on the most probable situation for different formation conditions. We conducted the comparative analysis of pressure drops and fracture width reductions for different types of fracture propagation. We also modeled fracture propagation for different perforation phasing angles. Based on the results of numerical experiments, we are able to provide some recommendations on how to avoid the worst case of the fracture initiation scenario.
The Effect of Proppant Distribution and Un-Propped Fracture Conductivity on Well Performance in Unconventional Gas Reservoirs
Authors: Cipolla C. L. , Lolon E. P. , Mayerhofer M. J. , Warpinski N. R. 
Published: January 2009

Abstract
Microseismic fracture mapping has provided significant insights into the nature of fracture growth in unconventional gas reservoirs (primarily shale) and allowed detailed characterization of the created network size and to a lesser extent the internal network structure (i.e., fracture spacings, azimuths, and degree of complexity). Fracture mapping has shown that large volume slickwater stimulations can access millions of square feet of reservoir area. In most unconventional gas reservoirs, well performance is directly related to the size and complexity of the fracture network; however, well performance is also affected by un-propped and propped fracture conductivity and proppant distribution within the fracture network. This paper examines the relationship between network size, proppant distribution, and well performance.
A series of reservoir simulations were used to quantify the effect of network fracture conductivity and proppant distribution on well performance. The simulations evaluate a range of reservoir permeability from 0.0001 to 0.01 mD and utilize a network size and fracture spacing that is consistent with microseismic mapping measurements. Proppant transport cannot be reliably modeled in complex fracture networks, but it is likely that much of the fracture network is un-propped (Cipolla et al.2008). Un-propped fracture conductivities of 0.5 to 5 mD-ft were evaluated in this study. This work investigates the effect of proppant transport from a primary fracture into a fracture network and proppant banking in the primary fracture on well productivity. The results of the reservoir simulations illustrate the likely impact of stimulation designs on well performance. The results from this work provide a better understanding of fracture conductivity requirements in unconventional gas reservoirs that can be used to improve stimulation designs through improved proppant selection and scheduling.
The results of the reservoir modeling show that proppant transport, even short distances, into the fracture network can have a significant affect on well productivity in cases where un-propped fracture conductivity is not adequate to fully exploit fracture complexity. In addition, proppant banking is likely with the low viscosity fluids used in many fracture treatments in unconventional gas reservoirs, which will result in the formation of a high conductivity arch at the top of the proppant bank. The impact of this high conductivity arch can be significant and affect treatment designs, many times reducing proppant volumes and conductivity requirements.
Computing Estimated Values of Optimal Fracture Half Length in the Tight Gas Sand Advisor Program
Authors: Wei Y. N. , Holditch S. A. 
Published: January 2009

Abstract
Producing natural gas from Tight Gas Sand (TGS) reservoirs is currently very important to the industry in North America and will be of increasing importance to the global energy industry in the coming decades. We are developing a TGS Advisory system to provide advice to engineers evaluating and developing tight gas sand reservoirs. The program can be used to establish best practices for drilling, completing, stimulating and producing a TGS reservoir as a function of the reservoir properties. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build TGS Advisor.
One of the most important problems for TGS reservoirs is to determine the optimum fracture half-length as a function of the reservoir properties. In this paper, we will describe three methods to calculate the optimum fracture half length, which include using 2-D fracture design equations, the unified fracture design method, and a rule-of-thumb method using the values of formation permeability and expected drainage area. With these three estimated values of optimum fracture half-length, the user can confidently use a 3-D or Pseudo 3-D fracture design model to generate the more detailed fracture treatment design. All the three methods have been incorporated into the TGS Advisory system. An example of using TGS Advisor to estimate the optimal fracture half-length will be presented.
Fracture Growth in Horizontal Injectors
Authors: Suri A. , Sharma M. M. 
Published: January 2009

Abstract
Horizontal wells are increasingly used worldwide and are especially desirable offshore for water-flooding and reservoir pressure maintenance as they allow more access to the reservoir with large injectivities. Fracture growth in these horizontal injectors can play an important role in determining the injection rates, reservoir sweep and oil recovery.
A model is developed to estimate the growth of fractures in horizontal injectors. The model considers two orientations of fracture growth: 1) longitudinal fractures i.e. fracture along the horizontal well and 2) centered transverse fractures, i.e. at the center and perpendicular to the horizontal well. Fracture growth is due to: 1) reduction of permeability around the horizontal well caused by particle deposition from injection fluids, 2) reduction in minimum horizontal stress due to cold fluid injection, and 3) injection of viscous polymer fluids. The model accounts for plugging of the horizontal well, the induced fracture and the formation around the fracture. It also calculates the thermal and pore pressure stresses to update the minimum horizontal stress around the fracture tip. It also allows injection of power-law fluids to model polymer injection in horizontal injectors.
It is shown that the injection well pressures are controlled by the minimum horizontal stress. The injection fluid quality, injection rate, and injection fluid temperature determine the rate of fracture growth in a horizontal injector. Fracture lengths are estimated for longitudinal and transverse fracture growth orientations as the lower and upper bound values.
New Frac Fluid Provides Excellent Proppant Transport and High Conductivity
Authors: Walters Harold G. , Stegent Neil , Harris Phillip C. 
Published: January 2009

Abstract
A new clean biopolymer-based fracturing fluid has been developed. The new fluid has high conductivity, stable viscosity, low pipe friction, excellent proppant transport, and the capability to be used with produced water. This fluid-system development effort was aided by the evolution of a new approach to proppant transport measurement as well as the operational deployment of a dry-polymer blender used to effectively hydrate the fluid system as part of an on-the-fly treatment. The new fluid has been field-trialed in 14 frac stages over four wells with about two million pounds of proppant placed. The application of the new fluid and experience of the field-trials are discussed.
This new clean fluid is widely applicable to fracturing low-permeability reservoirs worldwide and can be used where both waterfrac and traditional gelled fluids are currently used. This fluid signals a dramatic shift in fracturing low-permeability unconventional reservoirs by coupling excellent proppant transport with high conductivity.
Maximizing Return on Fracturing Investment by Using Ultra-Lightweight Proppants to Optimize Effective Fracture Area: Can Less Really Deliver More?
Authors: Brannon Harold D. , Starks Thomas R. 
Published: January 2009

Abstract
Hydraulic fracture deliverability is largely defined by the fracture area exhibiting sufficient conductivity contrast within the productive reservoir interval. Increasing effective fracture area has typically been addressed by employing larger treatments and proppant volumes, resulting in increased stimulation treatment costs, which unless accompanied by similar increase in the value of the incremental well productivity, has negative implications on ROFI.
The introduction of ultra-lightweight proppants having superior proppant transportability relative to conventional proppants and sufficient strength to withstand the harsh environments has spurred renewed interest in the application of proppant partial monolayers (PMLs). A properly placed partial monolayer exhibits conductivity equivalent to packed fractures having greater than ten proppant layers. The enhanced transportability of the ULW proppants allows for distribution over a much greater portion of the created fracture area. Thus, ULW proppant partial monolayers equate to a high conductivity fracture with much reduced volumes of proppant distributed across a larger area than can be achieved with conventional proppants. Case histories of PML fracturing treatments have consistently illustrated stimulated production increases well beyond expectations, effectively validating the productivity benefits of the process. This paper compares effective fracture area, fracture conductivity, and resultant production simulations for ULW proppants partial monolayer fracturing treatment designs with those of conventional proppant packed fractures. Normalized stimulation costs of the respective treatment designs are subsequently compared with the stimulated fracture deliverability to assess the respective Return-On-Fracture-Investment.
Solid Production Chemicals Added with the Frac for Scale, Paraffin and Asphaltene Inhibition
Authors: Gupta D. V. S. , Szymczak Steve , Brown Mike J. 
Published: January 2009

Abstract
Prolonged chemical inhibition is the desired outcome from placing a solid inhibitor in a formation during the fracturing process. Traditionally liquid inhibitors applied through a squeeze have provided inhibition for up to one year and sometimes longer. Deepwater operators, especially, desire longer inhibition periods. This paper reports on new fracture compatible chemistry that has been applied on over five hundred wells for the inhibition of mineral scale. It also reports on similar products for the inhibition of paraffin and asphaltene. These applications have been in deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over three and a half years. The highest cumulative water production with acceptable scale inhibitor residuals has been over 1,000,000 bbls of water.
Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading and minimize the chemical release rate without negatively impacting the stimulation.
In the treated wells, inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. This is a direct result of the placement of the inhibitor in the formation during the fracturing process. All wells have shown inhibition, as measured by produced fluid sample analyses.
All operators with deposition potential must undertake significant remedial intervention measures. This new chemical technology extends the life of a chemical inhibitor placement beyond traditional expectations. The advancement of this technology has reduced deposition-related failures and reduced well intervention costs.
Unconventional Fracturing Fluids for Tight Gas Reservoirs
Authors: Gupta D. V. S. 
Published: January 2009

Abstract
Many tight gas formations are water-wet and under-saturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. The use of water-based conventional fracturing fluids causes water to be trapped in the near-wellbore region, thereby significantly impairing the ability of gas to flow. Formations with sub-irreducible water saturation can be stimulated with fluids that minimize the interfacial tension (such as surfactant gels), minimize the amount of water used in the fluid (such as energized or foamed fluids), dehydrate the formation (such as alcohol-based fluids) or completely eliminate water (such as hydrocarbon-based or liquid carbon dioxide-based fluids). Since the rheology and proppant-carrying properties of these fluids vary, the uses of these fluids are different and will be discussed in detail in the paper. The paper will also present guidelines, based on formation properties, to indicate the need for considering unconventional fluids.
Hydraulic Fracturing: Modeling and Optimization Using Latest Generation Logs and Conductivity Optimization Technologies
Authors: Espina C. , Baldassa D. , Sorenson F. , López E. , Bonapace J. , Quintavalla C. 
Published: January 2009

Abstract
Successful hydrocarbon production in the San Jorge Basin in Argentina is achieved with understanding the high variations in reservoir fluid properties, discriminating the complex lithology, and achieving the optimum hydraulic fractures. This paper outlines how state of the art logging tools and collaboration between the operating and service companies can deliver improved fracture results.
The multi-layered stratigraphic formations in the San Jorge Basin have long presented formation evaluation challenges with conventional well logging. These formations exhibit major inconsistencies and anomalous results in formation water salinity. In addition, the complex reservoir characteristics have required the use of hydraulic fracturing to improve the hydrocarbon production during the past fifteen years.
Nowadays, petrophysical evaluation of the reservoirs has been improved using the latest well logging technology such as Nuclear Magnetic Resonance (NMR) logs to identify and distinguish potential productive layers and zones to be stimulated.
Combining NMR logging technology with fracture height evaluation utilizing azimuthal shear wave slowness data, stimulation treatment pressure responses, and post-stimulation swab test results, provides sufficient data to calibrate geomechanical and hydraulic fracturing models. With advanced interpretation techniques and modeling, the optimum fracture can be designed and performance data from that fracture can be used to validate the theoretical models. This approach enhances the capability to design hydraulic fractures based on the reservoir conditions, with the optimum conductivity and fracture half-length to provide the required productivity over the life of the well.
Application of this process has resulted in improved well performance in the San Jorge Basin wells. The integration and interpretation of information between the operator and the service companies resulted in more accurate and optimized work flows and modeling for the complex and non-conventional reservoirs of the San Jorge Basin. As companies work together in a collaborative environment to address business challenges, solutions have been generated that no single company could have achieved alone.