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Abstract Fracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments. A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells. The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.
Awan, Faisal Ur Rahman (Edith Cowan University, Joondalup, Australia) | Keshavarz, Alireza (Edith Cowan University, Joondalup, Australia) | Akhondzadeh, Hamed (Edith Cowan University, Joondalup, Australia) | Nosrati, Ataollah (Edith Cowan University, Joondalup, Australia) | Al-Anssari, Sarmad (University of Baghdad, Baghdad, Iraq) | Iglauer, Stefan (Edith Cowan University, Joondalup, Australia)
Coal fines are highly prone to be generated in all stages of Coal Seam Gas (CSG) production and development. These detached fines tend to aggregate, contributing to pore throat blockage and permeability reduction. Thus, this work explores the dispersion stability of coal fines in CSG reservoirs and proposes a new additive to be used in the formulation of the hydraulic fracturing fluid to keep the fines dispersed in the fluid. In this work, bituminous coal fines were tested in various suspensions in order to study their dispersion stability. The aggregation behavior of coal fines (dispersed phase) was analyzed in different dispersion mediums, including deionized-water, low and high sodium chloride solutions. Furthermore, the effect of Sodium Dodecyl Benzene Sulfonate (SDBS), an anionic surfactant, on fine aggregation in the suspensions was investigated over a wide alkaline range. At a known pH, the results of stability were validated with the proppant pack glass column test and further verified with microscopic images. It was observed that adding SDBS to the hydraulic fracturing fluid keeps the coal fines well-dispersed in the post-hydraulic fracturing flow back and prevents coal fines aggregation, and ultimately helps permeability enhancement. The results show that at a constant pH, as salinity increases, the zeta-potential (an indirect indicator of stability of the coal-water slurry) reduces. Also, a trace amount of SDBS substantially enhances the dispersion stability of coal fines. This enhancement dictates that coal fines will not congregate and will not plug the proppant pack. Furthermore, the results were confirmed by proppant pack glass-column tests and microscopic images, the result of which illustrate much less aggregation when having SDBS added to the suspension. Polymeric surfactants have been used in the field to disperse coal fines. However, it causes the coal matrix to swell and clog the pore throats, thus reducing the permeability. The anionic surfactant, SDBS, has never been tried in field applications to disperse coal fines. The current research demonstrates the considerable potential of SDBS, as a hydraulic fracturing fluid additive, in enhancing the dispersion stability of the coal fines.
Keshavarz, A.. (Australian School of Petroleum, The University of Adelaide) | Badalyan, A.. (Australian School of Petroleum, The University of Adelaide) | Carageorgos, T.. (Australian School of Petroleum, The University of Adelaide) | Johnson, R. L. (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, P. G. (Australian School of Petroleum, The University of Adelaide)
Abstract The physical model and experimental data support the beneficial technology of graded proppant injection into naturally fractured reservoirs to stimulate natural fracture permeability. Injection of particles with increasing size, at poroelastic and hydraulic fracturing conditions, yield deeper penetration and gradual filling of natural fractures with a resulting increase in permeability. This work expands on the concepts and outlines steps to maximize the benefit of graded proppant injection to enhance coal seam gas stimulation by focusing on the effect of the chemistry of injected fluid on the overall performance and the use in conjunction with hydraulic fracturing. Low productivity indices can be observed in many moderate- to low-permeability coal bed methane (CSG) reservoirs due to low aperture and poor connectivity of natural cleats. Graded proppant injection in CSG environments can: stimulate a stress sensitive cleat system below the fracturing pressure as well as enhance a fracturing treatment by invading cleats, lowering fluid leakoff, and maintaining aperture during production. Further, periodic or remedial treatments could to counter effective stress on the cleats improving production by maintaining cleat aperture. Laboratory tests on coal core flooding by water under increasing pore pressure with proppant injection at the maximum pressure have been carried out under different salinities of the injected water. Proppant-proppant and proppant-coal Derjaguin-Landau-Verwey-Overbeek (DLVO) total interaction energies were calculated to optimise the condition for successful proppant placement. Results on the DLVO total energy of interaction showed that conditions favourable for successful proppant placement in coal cleats are suspension ionic strengths between 0.05 M and 0.1 M NaCl. At these conditions no proppant agglomeration and proppant-coal attachment are observed, allowing deeper penetration of proppant into the natural coal cleat system. Lower suspension ionic strengths can lead to natural coal fines migration, cleat plugging and coal permeability reduction. Based on the experimental results and previously developed model a case study has been conducted to evaluate the productivity enhancement using this technique. The results show about four-fold increase in well productivity index at injections below fracturing pressures and may further improve the stimulated reservoir volume when used in conjunction with low permeability coal hydraulic fracturing treatments.
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.
Abstract Many engineers disregard laboratory reports demonstrating that the pressure losses across proppant samples are substantial. Similarly, it appears that the modeling studies warning of substantial productivity losses due to inadequate fracture conductivity have not been universally convincing. Perhaps many practical frac engineers simply object to the theoretical nature of these arguments, when they quote one of the more influential orators of our time, Shania Twain, stating, "That don't impress me much." Instead, many Petroleum Engineers prefer to see the economic benefit demonstrated in real reservoirs, and seemingly borrow a quotation from the film Jerry Maguire, stating, "Show me the money!" The purpose of this paper is to summarize the results of over 80 field studies where well productivity was improved by increasing the fracture conductivity. The benefit of increased conductivity has been demonstrated in oil, condensate, and gas reservoirs in 50 regions around the globe.This benefit was documented by 250 authors representing over 70 companies. Increased conductivity has been shown to be beneficial in oil wells producing 2 bopd to 25,000 bopd, and in gas wells producing less than 1 MMCFD to over 100 MMCFD. Higher conductivity fractures were proven to improve the cash flow in carbonates and sandstones at depths of 2800 to 20,000 feet, and in low rate coal bed methane wells shallower than 1500 feet. This review of industry experiences in a wide variety of reservoirs is not presented as a substitute for a comprehensive optimization study in a specific location. Instead, the following summary demonstrates that well productivity and profitability can frequently be improved with redesign of hydraulic fractures, despite the failure of many existing production models to predict those benefits. These studies are presented to satisfy the following goals:To verify that the extreme pressure losses observed in the laboratory and predicted by current fluid flow theory are real, i.e., "Proving It". To provide a list of fields, encompassing a wide variety of reservoir types, to assist engineers searching for results from an analogous field. To provide a number of field studies to which production models can be calibrated. To summarize the collective experience of over 250 authors, and incorporate what they have learned into future fracture designs. To demonstrate the relationship between fracture conductivity, well productivity, and cash flow, i.e., "Show me the money!" Introduction Over 100 years ago, Forchheimer recognized that fluid flow through porous media obeyed Darcy's Law only at extremely low seepage velocities. At typical velocities experienced in hydraulic fractures, the pressure losses actually consist of both a frictional and an inertial component. In other engineering disciplines, this concept is well accepted. Chemical Engineers routinely use this relationship (referred to by them as the Ergun Equation) to describe fluid flow through catalyst beds and media filters. Automotive Engineers similarly understand that the pressure drop within a catalytic converter is not adequately described by Darcy's Law. In most industries, it is simple to measure the pressure loss across the system and use the correct equation. However, as Petroleum Engineers frequently pump proppant down a mile of pipe, and hundreds of feet away from the wellbore, our mistake may not be as readily apparent. Since we have yet to invent a remotely transmitting pressure gauge to place in the propped fracture, we instead choose to stick our heads in the sand and ignorantly assume Darcy's Law will adequately describe fluid flow in hydraulic fractures. We are simply wrong.