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Collaborating Authors
United States
Summary The redistribution of stresses around a fractured vertical well has two sources: opening of propped fracture (mechanical effects) and production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations. For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress-reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves. The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado), with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model. This paper introduces a 3D model, coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to select candidate wells, choose the timing of the refracture operation in the life of the well, and evaluate the potential increase in well production after refracturing.
- North America > United States > Colorado > Weld County (0.45)
- North America > United States > Colorado > Larimer County (0.45)
- North America > United States > Colorado > Denver County (0.45)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.40)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Wattenberg Field (0.99)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
Abstract A proppant-filled fracture induces mechanical stresses in the surrounding rock causing a reduction in the stress contrast and stress re-orientation around the open fracture. A three-dimensional geo-mechanical model is used to simulate the stress reorientation due to open fractures and generate the stress contrast contour maps. The reduction in stress contrast can lead to increased fracture complexity. This paper describes how fracture complexity can be increased by varying the completion design. In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more effective completion designs that improve well productivity, reservoir drainage and ultimately EUR. The possibility of greater fracture complexity and reduced effective fracture spacing and hence higher drainage area is demonstrated for an alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young's modulus value of the shale and the in-situ horizontal stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage and the fluid rheology is also shown to significantly impact fracture complexity. We provide optimum ranges of fracture spacing, proppant volume and fluid rheologythe various formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed. The results presented in the paper allow an operator to design completions and fracture treatments (rates, fluids, fracture spacing and sequencing) to maximize reservoir drainage and increase EURs. This will lead to more effective completion designs.
A New Family of Nanoparticle Based Drilling Fluids
Sharma, Mukul M. (The University of Texas at Austin) | Zhang, R.. (China University of Petroleum) | Chenevert, M. E. (The University of Texas at Austin) | Ji, L.. (China University of Petroleum) | Guo, Q.. (China University of Petroleum) | Friedheim, J.. (M-I SWACO)
Abstract A new family of water-based drilling fluids that contain nano-particles has been tested to evaluate its interaction with shales. It was shown in an earlier paper that nano-particles dramatically reduce the flow of water into a shale formation. In this study we have developed and tested a new family of commercially available drilling fluids that can be used to drill shales. Drilling shale formations with water-based fluids offers some tremendous environmental and economic advantages. To date the use of such fluids have been limited to hard shales such as the Barnett. In this paper we have developed and lab tested water-based drilling fluids that contain nano-particles that can be applied to a much broader range of shales. Water-based drilling fluids have been formulated that incorporate nano-particles in them at a very reasonable cost. The rheology and stability of these muds were tested. A family of such fluids has been developed and tested in the lab. It is found that the muds are quite stable at elevated pressures and temperatures and offer a wide range of rheological properties. These muds also offer good lubricity and are, therefore suitable for applications in drilling the lateral section of the hole in shales. Tests were also conducted to measure the extent of invasion of water into shales when they are exposed to nano-particle based drilling fluids. The invasion into the shale was reduced by 10 to 100 times indicating that wellbore instability problems will be minimized when these muds are used. Drilling long lateral sections in shales and tight gas reservoirs is often the largest capital cost associated with the development of these resources. Nano-particle based drilling fluids have the potential to significantly cut these drilling and disposal costs and offer significant environmental benefits.
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (3 more...)
Abstract Horizontal completions have changed considerably in the last few years in an effort to substantially improve the drainage of shale gas reservoirs. The spacing of fracture stages and perforation clusters are among the most crucial completion decisions that impact well productivity and EUR. Yet, the decision regarding stage spacing is rarely guided by an engineering process, as it remains a challenge to tie production performance and completion design. In this paper, we offer some insight on the impact of fracture spacing on the propagation direction of multiple transverse fractures, and consequently the expected performance of the horizontal well. Stress-shadow effects, related to the mechanical interference induced by a proppant-filled fracture, can cause fractures initiated from a horizontal well to deviate toward or away from previous fractures. A three-dimensional geomechanical model of the combined stress interference from multiple transverse fractures has been applied to typical wells in three shale gas reservoirs: Bakken, Barnett and Eagle Ford. The existence of an optimum spacing is demonstrated, where fracture stages remain transverse even when subject to stress-shadow effects. Below the optimum spacing, induced fractures may intersect previous fractures, and re-stimulate previously fractured regions of the reservoir, while leaving undrained portions of the reservoir un-stimulated. Such behavior is highly dependent on the mechanical properties of the shale, in particular the Young’s modulus. Our modeling results suggest that the net fracturing pressure data measured in the field reflects the propagation direction of the fractures induced from the horizontal wellbore. A monotonic increase in net pressure, going from one stage to another, would indicate transverse fracture propagation during all stages. On the other hand, an up-and-down trend in the net pressure data is an indication that the mechanical stress interference is causing the later stage fractures to intersect fractures from previous stages. The net pressure data can, therefore, be used to investigate fracture-to-fracture interference and can be used to optimize the spacing of fracture stages in horizontal completions.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.79)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.70)
- North America > United States > Texas > Fort Worth Basin > Barnett Field > Barnett Shale Formation (0.98)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.96)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.93)
- (5 more...)