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Cohen, C.E. (Schlumberger) | Abad, C. (Schlumberger) | Weng, X. (Schlumberger) | England, K. (Schlumberger) | Phatak, A. (Schlumberger) | Kresse, O. (Schlumberger) | Nevvonen, O. (Schlumberger) | Laffite, V. (Schlumberger) | Abivin, P. (Schlumberger)
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures.
This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young‘s modulus - on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.
This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
Phatak, Alhad (Schlumberger) | Kresse, Olga (Schlumberger) | Nevvonen, Olga Vladimirovna (Schlumberger) | Abad, Carlos (Schlumberger) | Cohen, Charles-edouard (Schlumberger) | Lafitte, Valerie (Schlumberger) | Abivin, Patrice (Schlumberger) | Weng, Xiaowei (Schlumberger) | England, Kevin W. (Schlumberger)
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design which have improved productivity in these reservoirs. However, further advances in treatment design require a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and interaction with natural fractures.
This paper investigates the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters, with a focus on proppant and fluid selection. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model, with the Unconventional Production Model is presented. This workflow has shown qualitative consistency with real production data.
In this paper we applied the workflow on a realistic reservoir with characteristics from the Marcellus play, and then studied the relation between production and treatment design parameters such as proppant size, proppant concentration, the treatment volume of the treatment, fracturing fluid viscosity, pumping rate and proppant injection sequence.
Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fluid viscosity for every parameter. More than four hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.
The behaviors observed confirm several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. Another key finding is that the optimum fluid viscosity increases with treatment volume, and decreases when pumping rate increases.
The evolution of fracturing technology has provided the industry with numerous advances, ranging from sophisticated fluid systems, to tip screen out designs, to propagation modeling. Interestingly, these advances have typically been focused on ‘conventional' designs which utilize a cross-linked fluid system. However, as the development of unconventional (tight gas, shales, coal-bed methane etc) or underpressured reservoirs has increased, so has the demand for innovative hydraulic fracture
designs. The most recent of these design changes has been the popular method of placing proppant with slickwater, linear gel or hybrid treatments.
Although our industry has significant expertise in fracture design, most of our experience has been in conventional crosslinked fluid systems. However, there are many aspects of cross-linked fluid design that either do not apply to slickwater treatments, or in some cases are exactly opposite.
This paper will begin by reviewing the motivation, benefits and concerns with slickwater fracturing, and discuss why this seemingly ‘old' method has regained popularity over conventional cross-linked designs in many reservoirs. In addition, the authors will detail some of the important theories related to slickwater fracturing, including fracture width and complexity, proppant transport and settling, and conductivity requirements. In each case, emphasis will be placed on the different strategy that must be employed compared to cross-linked fluid designs, and highlight the mistakes or misunderstandings that are frequently made.
Where appropriate, lab testing, field measurements, reference material and other resources are presented to support the observations made by the authors. This paper will serve as a resource to any engineer or technician who is designing/pumping slickwater fracs, or who is considering this technology for potential application. By applying the
concepts presented in this paper, engineers will be able to appropriately evaluate the potential benefits of using this technique in their completions, as well as draw on the experiences of others to take full advantage of this technology.
Hydraulic fracturing is arguably one of the most leveraging completion technologies, particularly in gas wells. This practice has also been a key factor in unlocking the potential of unconventional gas plays, such as coal-bed methane, tight gas and shale gas reservoirs. However, shortly after the first commercial fracture treatment was performed in 1947 using gasolinebased napalm gel frac fluid, two primary design parameters were established: 1) fractures created by "hydrafracs?? tended to heal unless a propping agent was placed, and 2) frac fluids required elevated viscosity to create adequate width and proppant transport, and to minimize leak offi.
Approximately 20 years later guar-based crosslinked fluids were introduced and, along with their synthetic counterpart, became the mainstay of fracturing fluidsii. By the 1980's it was not uncommon for operators to place massive hydraulic fractures (MHF) in excess of 2 million lbm of proppant, utilizing 60 pptg guar crosslinked geliii. However in 1997 a relatively (in)famous case study in the East Texas Cotton Valley formation purported that "we don't need no proppants??iv. This study laid the foundation for the technology that induced nearly a 180 degree reversal from the MHF treatments a decade earlier, and quickly spread to other areasv. The driving factors of this "waterfrac?? phenomenon were primarily tied to three reasons: 1) the necessity of cost cutting as commodity prices fell, 2) the reservoirs being fractured were either depleted or lower
permeability and as such were not able to effectively "clean-up?? the gel from the fracture, and 3) the recognition that fractures were not performing as well as expected (much shorter effective half lengths than placed/designed). In fact, the primary conclusion of SPE 38611 was that "waterfracs are successful because they achieve, at a lower cost, the same inferior stimulation as a conventional job with inefficient cleanup?? (emphasis added).
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/ CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity. In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance. The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate.
Many engineers today do not have the training needed to fully understand the importance of fracture mechanics principles and are easily overwhelmed in trying to deal with proper proppant and fluid selections, perforation design and strategy, and on-site quality control of the fracturing process. The unfortunate reality is that many fracture designs are improperly engineered with critical reservoir and hydraulic fracture parameters either ignored or improperly addressed. Many completions are either marginally economical or produce at reduced commercial rates. Regardless of reservoir type, it is critically important to achieve a highly conductive hydraulic fracture that provides connectivity between the reservoir and the wellbore.
Since its inception, fracturing and completion knowledge has expanded exponentially allowing the oil and gas industry to develop ultra-low permeability unconventional reservoirs. During the 1980's and 1990's technology pioneers such as Holditch, Nolte, Warpinski, Veatch, and others, further developed the principles of fracturing which recognize the importance of critical fracture parameters and their effect upon initial productivity and ultimate recovery. These gains in expertise have resulted in unprecedented activity in the Bakken, Eagle Ford, Barnett, Haynesville, and Marcellus with increasing activity in new reservoirs such as the Utica, Niobrara, and Mississippian. Although each of these reservoirs is unconventional, each is uniquely different with respect to lithology, permeability, and hydrocarbon chemistry and interaction.
This paper will challenge the industry notion that infinitely conductive fractures are being placed in many unconventional completions. It further addresses the critical fracturing parameters required to achieve a high conductivity fracture, why they are important, and how to achieve proper proppant and fluid treatment designs. The importance of these fundamental principles is documented and illustrated by several case histories which demonstrate the value of achieving high conductivity fractures and the effects of improper design. This paper should be of great value to completion and operation
s engineers to help further their knowledge with regard to the importance of fracture conductivity and connectivity in all hydraulic fracturing applications.