**Source**

**SPE Disciplines**

**Conference**

- SPE Canadian Unconventional Resources Conference (1)
- SPE Eastern Regional Meeting (1)
- SPE Hydraulic Fracturing Technology Conference (1)
- SPE International Symposium and Exhibition on Formation Damage Control (1)
- SPE Western Regional Meeting (1)
- SPE/EAGE European Unconventional Resources Conference and Exhibition (1)

**Publisher**

**Theme**

**Concept Tag**

- approach (1)
- Artificial Intelligence (2)
- calculation (2)
- closure (2)
- condition (1)
- conductivity (1)
- configuration (1)
- containment (1)
- containment layer (1)
- design (3)
- downhole intervention (4)
- Eagle Ford shale (1)
- Energy Economics (1)
- equilibrium (1)
- Figure (1)
- flow in porous media (2)
- Fluid Dynamics (4)
- formation evaluation (5)
- fracture (6)
- fracture design (2)
- fracture geometry (1)
- fracture height (3)
- height (2)
- Horizontal (1)
- horizontal well (3)
- layer (2)
- LEFM (1)
- Maximum (1)
- mesh sand (1)
- model (3)
- NPV (2)
- number (1)
- optimization (1)
- optimization problem (6)
- paper (1)
- permeability (3)
- pressure (5)
- produced water (3)
- production control (6)
- production enhancement (4)
- production monitoring (6)
- productivity (1)
- productivity index (4)
- proppant (6)
- Proppant Number (3)
- proppant pack permeability (1)
- psi (2)
- psi closure pressure (1)
- ref (1)
- reservoir simulation (6)
- sand (3)
- shale (2)
- shale gas (3)
- SPE (2)
- stage (1)
- stress (3)
- Table (1)
- tip (1)
- treatment (1)
- well (3)
- width (1)

**Industry**

**Oilfield Places**

**Technology**

**File Type**

We have published already a three-layer *p*-3D fracture design optimization using the Unified Fracture Design (UFD) approach; fracture height, resulting from fracture geometry optimization and therefore net pressure, was matched against the value resulting from fracture height migration at the same pressure.

For a multi-layered formation a more robust and more general approach is suggested in this work. First a range of admissible reference treating pressures is prepared. For each pressure level we determine the up-down tip locations and hence we obtain the fracture height map. Thus, there is a relationship between induced height and net pressure and this relationship can be calculated from Linear Elastic Fracture mechanics before the actual design optimization is carried out.

According to the applicable fracture propagation model, for a given fracture half length, there exists a width and henceforth a net pressure. The ancillary height is a geometric byproduct. Matching the net pressure and height with the LEFM independently determined pair of height and net pressure results in a solution that satisfies both. The dimensionless productivity index, *J _{D}*, is then calculated.

For the fracture half lengths, ranging from a minimum (corresponding to aspect ratio one with respect to the perforated thickness) to a laterally fully penetrating fracture, we repeat the above procedure to calculate *J _{D}* and so forth, until a maximum

approach, Artificial Intelligence, calculation, design, downhole intervention, fracture, fracture design, fracture height, model, optimization problem, paper, pressure, production control, production enhancement, production monitoring, productivity index, proppant, Proppant Number, reservoir simulation, shale, SPE, stress

Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are important elements in gaining the highest Net Present Value (NPV).

It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. A commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environments, invariably, deeper reservoirs.

The characteristics of most shale plays are very different, mainly as regards to the rock stiffness, exemplified by the Young's Modulus, stress anisotropy/isotropy and the existence of natural fracture network. Fracture strategies in shale formations are very different. This study presents fracture designs based on three types of proppants for shale formations: Brady sand, Ottawa sand and ceramic. Permeability tests and crush tests under certain pressure range are done to determine experimentally the dimensioned fracture conductivity. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered for gas reservoirs. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. NPV analysis is employed as the criterion to select the best proppant for the job. Finally, the completion and production data from example wells will be analyzed for comparison purpose.

In this work, we try to correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.

doi: 10.2118/161355-MS

SPE-161355-MS

closure, conductivity, Energy Economics, flow in porous media, Fluid Dynamics, formation evaluation, fracture, horizontal well, mesh sand, number, optimization, optimization problem, permeability, pressure, produced water, production control, production monitoring, productivity index, proppant, reservoir simulation, sand, shale gas, Table, well

Oilfield Places:

- North America > United States > Texas > Permian Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale (0.99)
- North America > United States > Texas > Eagle Ford Shale (0.99)
- (5 more...)

SPE Disciplines: Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)

Proppants are essential to the success of most hydraulic fractures and often account for a significant portion of the cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are critical elements in gaining the highest Net Present Value (NPV).

It has been generally believed that in a lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa types are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably deeper reservoirs.

According to the characteristics of Eagle Ford shale, which include the rock stiffness, exemplified by Young's Modulus, stress anisotropy or isotropy and the existence of a natural fracture network, this study presents fracture designs based on three types of proppants for both shale formations: Brady sand, Ottawa sand and man-made ceramic. Permeability tests and crush tests under certain pressure ranges are done to determine experimentally the dimensioned fracture conductivity. Although natural proppants may exhibit lower permeability, a fracture optimization p-3D model is used to remedy the lower proppant permeability and maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered for gas reservoirs. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production estimates over the well life. Finally, a NPV analysis is employed as the criterion to select the best proppant for the job.

In this study, we show there is an optimum Proppant Number corresponding to maximum NPV for various reservoir permeabilities. Based on that notion, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. By keeping stimulation costs down, natural sand proppants have a much larger range of applicability than previously thought.

doi: 10.2118/153811-MS

SPE-153811-MS

closure, downhole intervention, Eagle Ford shale, flow in porous media, Fluid Dynamics, formation evaluation, fracture, Horizontal, horizontal well, NPV, optimization problem, permeability, pressure, produced water, production control, production enhancement, production monitoring, proppant, Proppant Number, psi, psi closure pressure, reservoir simulation, sand, shale gas, stage, well

Oilfield Places:

- North America > United States > Texas > Fort Worth Basin > Barnett Shale (0.99)
- North America > United States > Texas > Eagle Ford Shale (0.99)
- North America > United States > Texas > Jordan Oil Field (0.98)
- (4 more...)

SPE Disciplines:

Systematic design and optimization procedures for hydraulic fracturing are available using two-dimensional (2D) (with constant fracture height) and pseudo-three-dimensional (p-3D) models to maximize well production by optimizing fracture geometry, including fracture height, half-length and width.

A multi-layered p-3D approach to design is proposed integrating Unified Fracture Design (UFD), fracture propagation models and Linear Elastic Fracture Mechanics (LEFM) relationship to generate optimized fracture geometry, including fracture height, width and half-length to achieve the maximized production. Containment layers are discretized to allow for plausible fracture heights when seeking convergence of fracture height and net pressure.

UFD sizes the fracture geometry to physically optimize the hydraulically fractured well performance. The Proppant Number is a correlating parameter, which in turn provides the maximum dimensionless productivity index (JD) corresponding to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the optimum fracture dimensions, i.e., fracture length and width, are set. However, UFD in its original form needs the ability to calculate the Proppant Number and that is possible only if fracture height is an input parameter and hence fraction of proppant ending up in the pay can be determined before the optimization.

PKN or KGD fracture propagation models in design mode provide basic treatment parameters to achieve a known target length and also associated net pressure. Linear Elastic Fracture Mechanics (LEFM) relationship can be used to obtain fracture height associated to a given vertical pressure distribution via vertical stress profile and fracture toughness profile. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the potential equilibrium height defined by the condition where the stress intensity factor minus fracture toughness difference changes sign (but not necessary becomes zero.)

After an equilibrium height and the corresponding net pressure are found, an optimization is carried out to find target length and a 2D design model is used to calculate treatment parameters, first of all net pressure. The ultimate goal is to find a consistent pair of these two different sub-models; when the assumed pressure condition in the LEFM part coincides with the resulting pressure condition from the UFD/2D part. Parts of this work also allows for determining conditions to avoid propagating into unintended layers (i.e. gas cap and/or aquifer) or to assure coverage of intended layers (such as a non-perforated layer with recoverable hydrocarbon.)

Artificial Intelligence, calculation, condition, configuration, design, formation evaluation, fracture, fracture height, height, layer, LEFM, model, optimization problem, pressure, production control, production monitoring, proppant, psi, ref, reservoir simulation, shale, SPE, stress, tip, treatment

Systematic design and optimization procedures for hydraulic fracturing are available using two-dimensional (2D) (with constant fracture height) and pseudo three dimensional (p-3D) models to maximize well production by optimizing fracture geometry, including fracture height, half-length and width.

A multi-layered p-3D approach to design is proposed integrating Unified Fracture Design (UFD), fracture propagation models and Linear Elastic Fracture Mechanics (LEFM) relationship to generate optimized fracture geometry, including fracture height, width and half-length to achieve the maximized production. Containment layers are discretized to allow for plausible fracture heights when seeking convergence of fracture height and net pressure.

UFD sizes the fracture geometry to physically optimize the hydraulically fractured well performance. The Proppant Number is a correlating parameter, which in turn provides the maximum dimensionless productivity index (JD) corresponding to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set. However, UFD in its original form needs fracture height as an input parameter.

PKN or KGD fracture propagation models predict hydraulic fracture geometry and the associated net pressure. Linear Elastic Fracture Mechanics (LEFM) relationship calculates fracture height by finding the net pressure distribution at layers, which plays an important role when the fracture is propagating in the reservoir. In multi-layered reservoirs, the net pressure of each layer varies as a result of different rock properties. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the final equilibrium height defined by the condition where the fracture toughness equals the calculated stress intensity factor based on LEFM. After an equilibrium height and the corresponding net pressure at the center of perforation are obtained, PKN/KGD models are used again, to calculate fracture width and half-length at each layer. This work also allows for a calculation of the fracture height that would not propagate into unintended layers (i.e. gas cap and/or aquifer).

containment, containment layer, design, downhole intervention, equilibrium, Fluid Dynamics, formation evaluation, fracture, fracture design, fracture geometry, fracture height, height, layer, model, optimization problem, pressure, production control, production enhancement, production monitoring, productivity, productivity index, proppant, reservoir simulation, stress, width

Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are essential elements in gaining the highest Net Present Value (NPV).

It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably, deeper reservoirs.

Three types of proppants are studied for a gas reservoir of Eagle Ford basin: Brady sand, Ottawa sand and ceramic. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. Finally, NPV analysis is employed as the criterion to select the best proppant for the job.

In this project, we show there is an optimum Proppant Number corresponding to maximum NPV in various reservoir permeability. Based on that, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.

downhole intervention, Figure, Fluid Dynamics, formation evaluation, fracture, horizontal well, Maximum, NPV, optimization problem, permeability, produced water, production control, production enhancement, production monitoring, productivity index, proppant, Proppant Number, proppant pack permeability, reservoir simulation, sand, shale gas, well

Oilfield Places:

- North America > United States > Texas > Permian Basin (0.99)
- North America > United States > Texas > Fuhrman-Mascho Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale (0.99)
- (7 more...)

SPE Disciplines: Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)