This is an Adobe® Digital Edition and cannot be returned after purchase. Please read our prior to purchase. Using an interdisciplinary approach, this new book offers a basic yet comprehensive introduction to the completion and reservoir engineering aspects of hydraulic fracture stimulation.
Design and Appraisal of Hydraulic Fractures is divided into three sections. Section 1 covers the design and placement of a hydraulic fracture stimulation; topics include the basics of the hydraulic fracturing process, stress issues, fracture geometry, controls on generated length and width, fluid and proppant selection, quality control, and quality assurance. Section 2 introduces the use of dynamic data to characterize the in-place hydraulic fracture, outlining the methods of pressure-transient analysis for both pressure-drawdown and pressure-buildup tests. The discussion includes effective wellbore radius, effective fracture half-length, equivalent skin, and their relationships; simulated and field examples illustrate the basic analysis procedure and many common pitfalls. The final section covers the prediction of long-term rate performance and recoverable volumes. Three approaches are discussed: rate-decline type curves, analytical and semianalytical methods, and numerical simulation. Essential elements are given for each and illustrated with field examples.
Design and Appraisal of Hydraulic Fractures is a valuable reference for all members of the geotechnical and surface engineering communities who need to understand the important issues around and the full impact of hydraulic fracture stimulation on well performance.
Abstract In this work, the effect of fracture network connectivity on hydraulic fracturing effectiveness was investigated using a discrete element numerical model. The simulation results show that natural fracture density can significantly affect the hydraulic fracturing effectiveness, which was characterized by either the ratio of stimulated natural fracture area to hydraulic fracture area or the leakoff ratio. The sparse DFN cases showed a flat microseismic distribution zone with few events, while the dense DFN cases showed a complex microseismic map which indicated significant interaction between the hydraulic fracture and natural fractures.
Further, it was found that the initial natural fracture aperture affected the hydraulic fracturing effectiveness more for the dense natural fracture case than for the sparse (less dense) case. Overall, this work shows that fracture network connectivity plays a critical role in hydraulic fracturing effectiveness, which, in-turn, affects treating pressures, the created microseismicity and corresponding stimulated volume, and well production. Introduction The extremely low permeability of the common shale plays means that simple, bi-planar hydraulic fractures (HF) do not create enough surface area to make economic wells and that stimulation of the natural fracture system is critical. Numerous field microseismic data sets have shown that extreme fracture complexity may result from the interaction between a created hydraulic fracture and the pre-existing fracture network ,. Consequently, operators will often alter the stimulation design, by changing injection rate, viscosity, or other parameters, in order to improve the effectiveness of the stimulation in unconventional shale plays.
However, these design changes offer only a limited control on improving the stimulation of natural fractures because of a lack of understanding of the fundamental characteristics, behavior, and connectivity of the natural fracture network. The connectivity of the fracture network, for example, determines the overall hydraulic diffusivity of the formation and is a key to the resulting ‘complexity’ from a hydraulic fracture stimulation. A highly connected fracture network will allow more fluid leakoff into the rock mass and render pressure communication over large distances, whereas a partially or sparsely connected fracture network will favor the propagation of a new hydraulic fracture and may exhibit pressure isolation between very closely spaced hydraulic fractures.
The intricacy of fluid flow in fractured formation is mainly due to the complex geometries, patterns, and heterogeneity of the fracture network. The fracture network connectivity, therefore, has been shown to be a critical factor which affects treating pressures, the created microseismicity and corresponding SRV (Stimulated Rock Volume), and production. Numerous numerical modeling efforts have been conducted in order to understand the process of hydraulic fracture (HF) interaction with a complex natural fracture network ,.
However, relatively few works have focused on understanding the role of natural fracture network connectivity and its impact on the effectiveness of hydraulic fracturing of shale reservoirs and associated microseismicity generation. In this paper, a discussion of fracture network connectivity and how it is utilized in developing a discrete fracture network (DFN) is presented, which is then incorporated into a discrete element numerical model (DEM). The propagation of a HF in the fractured rock mass was then studied using the DEM, which allowed for fully coupled, hydro-mechanical simulations, including the generation of synthetic microseismicity.
Following previous work from the authors on parametric studies to analyze the influence of the mechanical and flow properties of the DFN and matrix on HF propagation, the influence of the DFN fracture network connectivity was analyzed in this work using common stimulation metrics such as SRV. The corresponding microseismic response was also calculated from the simulation results and related to the effective SRV. The results show not only the critical role that the DFN must play in resource evaluations, but also in completion design and stimulation optimization. Fracture network connectivity and DFN realization Fracture network connectivity is determined by many statistical characteristics, among them, fracture shape, fracture size distribution, fracture density (area of fracture per unit volume), orientation distribution, and aperture size distribution. The combinations of these statistical characteristics that describe the geometrical properties of a DFN define the macro-scale connectivity and directional flow preference of the DFN, and thus, are essential for the fluid transport characterization of an unconventional reservoir.
In this work, focus was placed on the effects of two statistical fracture characteristics, fracture density and initial aperture both individually and in combination, on hydraulic fracturing effectiveness and microseismicity generation. For the study, a DFN generator was developed that was capable of creating a fracture network that satisfied the assigned input statistical characteristics and allowed for the quantitative variation of network connectivity.
As shown in, two DFN configurations were realized, which represent a sparse DFN and a dense DFN, respectively. The sparse DFN had 191 fractures while the dense DFN had 482 fractures, or about 2.5 times more than the sparse DFN. The fractures were created in the common disk shape with a dip angle of 90 ° but either a 60 ° or 150 ° dip direction in order to construct two orthogonal fracture sets.
The P10 (the number of fractures along a line divided by the length of the line) for the sparse DFN and dense DFN was 0.079 m -1 and 0.28 m -1, respectively. The P32 (the sum of the areas of the fractures contained in a named volume divided by the same volume) for the sparse DFN and dense DFN was 0.031 m 2/m 3 and 0.075 m 2/m 3, respectively. In addition to DFN density, the effect of the initial DFN aperture was studied by considering two different values of initial aperture for the DFN fractures.
In the first case, it was assumed that the initial aperture of the DFN fractures was equal to 0.1 mm. In the second case, it was assumed that the DFN fracture aperture was 1.5 times greater and equal to 0.15 mm. The goal of this study was to investigate the effects of hydraulic fracturing in shale formations with different levels of DFN connectivity. It was assumed that the DFN fractures were static, meaning that, with the exception of the main hydraulic fracture itself, the process of fracture growth and propagation was not considered within the simulations.
3DEC hydraulic fracturing modeling capabilities The numerical code used in the simulations, 3DEC, is a three dimensional distinct element method for discontinuum modeling. It can simulate the response of discontinuous media, such as a jointed rock mass, subjected to either static or dynamic loading, which includes the simulation of fluid injection during a hydraulic fracture treatment. 3DEC’s ability to handle large block displacements makes it amenable to the simulation of hydraulic fracture propagation, fracture opening (both hydraulic fracture and natural fractures), and the rotation of individual blocks leading to fracture connections or pinching. Further, 3DEC includes the ability to model steady-state or transient-fracture fluid flow, where the flow logic includes a system of flow planes, flow pipes and flow knots.
While most of the existing commercial hydraulic fracture simulators are based upon a number of analytical assumptions, or limit the simulated fractures to be smooth, bi-planar cracks, 3DEC is capable of explicitly modeling the mechanical response of a fracture network to fluid injection as well as the interaction of a created hydraulic fracture (the HF plane needs to be pre-defined) with the existing natural fractures. 3DEC model setup The 3DEC simulation domain consisted of two parts: an inner core domain with the population of the DFN and an outer boundary domain, which extended to twice of the size of the core domain in order to minimize boundary effects. To port the created natural fractures to 3DEC, a procedure was developed to explicitly represent the generated DFN in the geomechanical model. For each DFN fracture, a search was performed to identify those 3DEC blocks that were intersected by the given fracture. The identified blocks were then cut through into two blocks by the fracture plane. Since the newly created plane between blocks might only have part of its area belonging to the given fracture (if the natural fracture did not fully cut the blocks), different fracture material properties were assigned to the portion of the newly created plane that fell within the geological fractures than to the unfractured portion that fell outside the geological fractures.
Shows the core simulation domain discretized by the dense DFN. Individual blocks are shown in variable color, while the plane between two blocks is a possible natural fracture. The size of the inner domain was 400×200×100 m. The directions of the three principal stresses are shown in, which are coincident with the three axes x, y and z. For all the simulations, the maximum horizontal stress (SHmax) was 55 MPa, the minimum horizontal stress (Shmin) was 50 MPa, and the vertical stress (Sv) was 60 MPa. The initial pore pressure was set to 45 MPa.
The Young’s modulus of the rock mass was set to 30.0 GPa and Poisson's ratio was set to 0.25. The injection point was located in the center of the domain along the predefined hydraulic fracture plane (the plane of y=0), which was parallel to SHmax.
The injection rate was 0.05 m 3/s and the fluid viscosity was 0.0015 Pa s. It was assumed that fluid flow only occurred in either the DFN or HF planes and that there was no fluid flow into the rock matrix during the simulations. Simulation results In this study, four simulation cases, consisting of two DFN configurations (i.e., the dense DFN and sparse DFN) and two initial DFN apertures (i.e., 0.1 mm and 0.15 mm) were analyzed. Shows a plan view of the contours of fracture pressure distribution at the XY plane of z=0 m after 900 s of injection time for the four tests. The fracture pressure contour plot suggests two major observations.
With the same initial DFN aperture, the case with the dense DFN resulted in significantly more stimulated DFN area and less stimulated HF area than the case with the sparse DFN. In addition, with the same DFN configuration, the case with 0.15 mm initial aperture resulted in more stimulated DFN area and less stimulated HF area than the case with 0.1 mm initial aperture.
These results are also confirmed by the shorter hydraulic fracture lengths in the dense DFN simulations. These qualitative conclusions are as expected. Since hydraulic fracturing represents, essentially, the release (injection) of hydraulic energy into the formation, the injected fluid will follow the least resistive path. For the dense DFN, it was easier for fluid to enter the natural fractures than it was for the fluid to propagate a hydraulic fracture. Plan view of contours of fracture pressure distribution at the XY plane of z=0 m after a 900 s injection time for the cases of sparse and dense DFN realizations with two initial DFN apertures. The synthetic microseismic events during the injection can be approximated based on the magnitude of plastic slip. Plots the synthetic microseismic moment magnitudes for the sparse and dense DFN with the same initial aperture (0.1 mm) after 900 s of injection time.
The events that clustered based on their spatial and temporal proximity were colored by the occurring time and sized by the microseismic moment magnitude. All events were projected onto the XY plane with z=0 m and the XZ plane with y=0 m (HF plane). Shows that the sparse DFN case had fewer microseismic events than the dense DFN case. The complexity of microseismic events for the dense DFN case was consistent with field observations and suggests an intensive interaction between the created hydraulic fracture and the natural fractures.
The two qualitative observations from were further proved quantitatively by tracking the evolution of stimulated DFN area and HF area. As there is no precise criteria for defining the stimulated area, a criteria based on fracture pressure change was employed in this work. The area of the DFN or HF planes having a fracture pressure increase of 0.5 MPa or 1 MPa above the initial fracture pressure was considered as the stimulated area. Synthetic microseismic events for the sparse and dense DFN with the same initial aperture 0.1 mm after 900 s of injection time. The synthetic microseismic events are colored by the occurring time and sized by moment magnitude and then projected in the XY plane with z=0 m and the XZ plane with y=0 m (HF plane). Shows the quantitative evolution of the stimulated DFN area with a fracture pressure increase greater than 0.5 MPa and 1 MPa for the four cases shown in. Shows that, with the same DFN configuration, the case with a 0.15 mm initial aperture produced about twice the stimulated DFN area as the case with a 0.1 mm initial aperture.
However, with the same initial aperture, the case with the dense DFN produced only slightly more stimulated DFN area than the case with a sparse DFN. Also shows that the effect of choosing a different fracture pressure increase threshold to define the stimulated DFN areas is more obvious for the dense DFN case. Stimulated DFN area with a fracture pressure increase greater than A) 0.5 MPa and B) 1 MPa for the four cases shown in. Plots the evolution of the stimulated HF area with a fracture pressure increase greater than 0.5 MPa and 1 MPa for the four cases shown in. Shows that, for the sparse DFN configuration, the case with a 0.15 mm initial aperture produced only slightly less stimulated HF area than the case with a 0.1 mm initial aperture, whereas for the dense DFN configuration, there was nearly a 20% reduction in stimulated HF area for the 0.15 mm initial aperture over the 0.1 initial aperture case. Comparing the same initial aperture cases, the cases with the dense DFN produced much less stimulated HF area than the cases with a sparse DFN.
Also shows that the stimulated HF areas for all four cases using the 0.5 MPa fracture pressure increase criteria were only slightly larger than the cases when using the 1.0 MPa fracture pressure increase criteria. It may be concluded from the above analysis that, in terms of the stimulated DFN area, the initial DFN aperture is a more sensitive parameter than the DFN density. On the contrary, in terms of the stimulated HF areas, the DFN density seems to be a more sensitive parameter than the initial DFN aperture. Stimulated HF area with a fracture pressure increase greater than A) 0.5 MPa and B) 1 MPa for the four cases shown in. The overall effect of fracture network connectivity on hydraulic fracturing effectiveness can also be characterized by the ratio of stimulated DFN area to stimulated HF area. Plots the ratio of stimulated DFN area to stimulated HF area with a fracture pressure increase of 0.5 MPa and 1 MPa for the four cases shown in.
It can be seen that a dense DFN created a much higher ratio of stimulated DFN area to stimulated HF area than did a sparse DFN for similar initial apertures. However, the effect of initial DFN aperture was more evident for the dense DFN configuration than for the sparse DFN configuration. Meanwhile, the effect of choosing a different fracture pressure increase threshold for the stimulated areas was more obvious in the dense DFN configuration than for the sparse DFN configuration. Another parameter to evaluate the overall effect of fracture network connectivity on hydraulic fracturing effectiveness is the leakoff ratio, which is defined as the ratio of fluid volume in the DFN over the total fluid volume injected into the model. Shows the leakoff ratio for the four cases shown in. Very similar with the analysis for the ratio of stimulated DFN area to stimulated HF area, DFN density is shown to significantly affect the leakoff ratio for both initial aperture cases, while the initial DFN aperture is seen to affect the dense DFN more than the sparse DFN configuration. Leakoff ratio for the four cases shown in.
And show, separately, the average DFN aperture and average HF aperture for the four cases shown in. The average DFN aperture for all cases increased only slightly during the injection, though it is worth mentioning that even though the natural fractures were only slightly opened, the leakoff ratio for the dense DFN cases reached about 50% or more. Relatively, the sparse DFN case showed a slightly greater increase of average DFN aperture than the dense DFN case with the same initial DFN aperture.
As expected, the average HF apertures for all cases were several times larger than the average DFN apertures. In addition, as shown in, the sparse DFN case had a much greater increase (more than double) in the average HF aperture than the dense DFN case with the same initial DFN aperture. DFN density significantly affected hydraulic fracturing effectiveness, characterized by either the ratio of stimulated DFN area to stimulated HF area or the leakoff ratio, for both initial apertures considered. Further, the initial DFN aperture affected the hydraulic fracturing effectiveness of the dense DFN configuration more than the sparse DFN configuration.
The sparse DFN cases showed a flat microseismic distribution zone with few events while the dense DFN cases showed a complex microseismic map that indicated the intensive interaction between hydraulic fracture and the natural fractures. For all cases, the average DFN aperture increased only slightly during the injection while the average HF aperture increased significantly and was several times larger than the average DFN apertures. Relatively, the sparse DFN case showed a greater increase of average DFN aperture and average HF aperture than the dense DFN case for the same initial DFN aperture.
This work suggests that fracture network connectivity plays a critical role in hydraulic fracturing effectiveness for unconventional shale developments, and fracture connectivity will play a significant role in optimizing treating pressures, the created microseismicity and corresponding SRV, and well production.
BRITT is an engineering consultant with NSI Fracturing, and President of Britt Rock Mechanics Laboratory at the University of Tulsa. Since joining NSI in early 1999, Larry has specialized in the development and application of tools for the post appraisal of hydraulic fracturing stimulations. Britt's experience includes the optimization, design, and execution of fracture stimulations and integrated field studies throughout the world. Prior to joining NSI he worked for Amoco Production Company for nearly twenty years. During the last six years with Amoco, he was fracturing team leader at Amoco's Technology Center in Tulsa, Oklahoma, where he was charged with managing the development and application of fracturing technology for Amoco's worldwide operations. Larry is the co-author of the SPE book 'Design and Appraisal of Hydraulic Fractures'. Larry is a distinguished member of the SPE and co-author of 'Hydraulic Fracturing' and on numerous SPE Forum Committees on gas reservoir engineering and hydraulic fracturing.
In addition, Larry has authored over thirty technical papers on reservoir management, pressure transient analysis, hydraulic fracturing, and horizontal well completion and stimulations. He is a graduate of the Missouri University of Science & Technology (MS&T) where he has a BS in Geological Engineering and a Professional Degree in Petroleum Engineering. He is an adjunct professor in the Petroleum Engineering Department at MS&T where he also serves on both the Petroleum Engineering and University Engineering Advisory Boards and is a member of the Academy of Mines and Metallurgy. Horizontal wells have become the industry standard for unconventional and tight formation gas reservoirs.
Because these reservoirs have poorer quality pay, it takes a good, well-planned completion and fracture stimulation(s) to make an economic well. Even in a sweet spot in the unconventional and tight gas reservoir, good completion and stimulation practices are required; otherwise, a marginal or uneconomic well will result. But what are good completion and stimulation practices in horizontal wells in these unconventional reservoirs? What are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals?
How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from the horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed during this course. This course will focus on some of the key elements of well completions and stimulation practices as they apply to horizontal wells in tight and unconventional reservoirs.
Optimization studies will be shown and used to highlight the importance of lateral length, number of fractures, inter-fracture distance, fracture half-length, and fracture conductivity. These results will be used to discuss the various completion choices such as cased and cemented, open hole with external casing packers, and open hole pump and pray techniques. This course also will address key risks to horizontal wells and develop risk mitigation strategies so that project economics can be maximized. In addition, tight and unconventional gas field case studies will be used to illustrate the application of these design, optimization, and risk mitigation strategies for horizontal wells in tight and unconventional gas reservoirs. 'I appreciated the problems.
This tested the learning that we gained. Great approach to test knowledge learned. Instructor is very well versed and his depth and breadth of knowledge was good.' - Reservoir Engineer 'Very thorough overview of the entirety of the completion/stimulation process. Great course!'
- Reservoir Engineer. How To:. Use key multi-disciplinary tools for successful completions and stimulations in unconventional resources. Understand the importance of geo-mechanics and rock mechanics to the success of transverse multiple fractured horizontal wells in unconventional resources.
Design And Appraisal Of Hydraulic Fractures Pdf Writers
Understand unconventional resource play completion options and selection processes. Apply principals and design of well stimulation treatments in unconventional resources. Employ critical data needs and collection techniques with minimal operational impact. Unconventional Resources Completion and Stimulation - URCS Discipline: Production and Completions Engineering Level: Foundation Duration: 5 days Instructor(s): Larry Britt Horizontal wells have become the industry standard for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay, it takes a good, well-planned completion and fracture stimulation(s) to make an economic well.
Even in a sweet spot in the unconventional and tight gas reservoir, good completion and stimulation practices are required; otherwise, a marginal or uneconomic well will result. But what are good completion and stimulation practices in horizontal wells in these unconventional reservoirs? What are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics?
How do we maximize the value from the horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed during this course. This course will focus on some of the key elements of well completions and stimulation practices as they apply to horizontal wells in tight and unconventional reservoirs.
Optimization studies will be shown and used to highlight the importance of lateral length, number of fractures, inter-fracture distance, fracture half-length, and fracture conductivity. These results will be used to discuss the various completion choices such as cased and cemented, open hole with external casing packers, and open hole pump and pray techniques. This course also will address key risks to horizontal wells and develop risk mitigation strategies so that project economics can be maximized. In addition, tight and unconventional gas field case studies will be used to illustrate the application of these design, optimization, and risk mitigation strategies for horizontal wells in tight and unconventional gas reservoirs. 'I appreciated the problems. This tested the learning that we gained.
Great approach to test knowledge learned. Instructor is very well versed and his depth and breadth of knowledge was good.' - Reservoir Engineer 'Very thorough overview of the entirety of the completion/stimulation process. Great course!' - Reservoir Engineer Designed For: Petroleum and production engineers, completion engineers, stimulation engineers, geologists, managers, technical supervisors, service and support personnel.
Microbial communities associated with produced water from hydraulic fracturing are not well understood, and their deleterious activity can lead to significant increases in production costs and adverse environmental impacts. In this study, we compared the microbial ecology in prefracturing fluids (fracturing source water and fracturing fluid) and produced water at multiple time points from a natural gas well in southwestern Pennsylvania using 16S rRNA gene-based clone libraries, pyrosequencing, and quantitative PCR. The majority of the bacterial community in prefracturing fluids constituted aerobic species affiliated with the class Alphaproteobacteria. However, their relative abundance decreased in produced water with an increase in halotolerant, anaerobic/facultative anaerobic species affiliated with the classes Clostridia, Bacilli, Gammaproteobacteria, Epsilonproteobacteria, Bacteroidia, and Fusobacteria.
Produced water collected at the last time point (day 187) consisted almost entirely of sequences similar to Clostridia and showed a decrease in bacterial abundance by 3 orders of magnitude compared to the prefracturing fluids and produced water samplesfrom earlier time points. Geochemical analysis showed that produced water contained higher concentrations of salts and total radioactivity compared to prefracturing fluids. This study provides evidence of long-term subsurface selection of the microbial community introduced through hydraulic fracturing, which may include significant implications for disinfection as well as reuse of produced water in future fracturing operations. Learn more about these metrics Article Views are the COUNTER-compliant sum of full text article downloads since November 2008 (both PDF and HTML) across all institutions and individuals. These metrics are regularly updated to reflect usage leading up to the last few days. The Altmetric Attention Score is a quantitative measure of the attention that a research article has received online. Clicking on the donut icon will load a page at altmetric.com with additional details about the score and the social media presence for the given article.
Find more information on.
The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. In the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing.
Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Contents. Overview Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking. During injection the resistance to flow in the formation increases, the pressure in the wellbore increases to a value called the break-down pressure, that is the sum of the in-situ compressive stress and the of the formation.
Once the formation “breaks down,” a fracture is formed, and the injected fluid flows through it. From a limited group of active perforations, ideally a single, vertical fracture is created that propagates in two 'wings' being 180° apart and identical in shape and size. In naturally fractured or cleated formations, it is possible that multiple fractures are created and/or the two wings evolve in a tree-like pattern with increasing number of branches away from the injection point. Fluid not containing any solid (called the “pad”) is injected first, until the fracture is wide enough to accept a. The purpose of the propping agent is to keep apart the fracture surfaces once the pumping operation ceases, the pressure in the fracture decreases below the compressive in-situ stress trying to close the fracture. In deep reservoirs, man-made ceramic beads are used to hold open or “prop” the fracture.
In shallow reservoirs, sand is normally used as the propping agent. Objectives In general, hydraulic fracture treatments are used to increase the productivity index of a producing well or the injectivity index of an injection well. The productivity index defines the rate at which oil or gas can be produced at a given pressure differential between the reservoir and the wellbore, while the injectivity index refers to the rate at which fluid can be injected into a well at a given pressure differential. There are many applications for hydraulic fracturing.
1—Typical input data for a P3D model. The data used to design a fracture treatment can be obtained from several sources, such as:. Drilling records. Completion records. Well files. Openhole geophysical logs. Cores and core analyses.
Well tests. Production data. Geologic records.
Other public records, such as publications In addition, service companies provide data on their fluids, additives, and propping agents. Table 1 illustrates typical data needed to design a fracture treatment and possible sources for the data. 2—Fracture treatment optimization process.