Publications
All SPE papers are property of the Society of Petroleum Engineers and .pdf files can be obtain from their website.
2007
Green, C.A., Barree, R.D., and Miskimins, J.L.: "Hydraulic Fracture Model Sensitivity Analysis of a Massively Stacked, Lenticular, Tight Gas Reservoir", paper SPE 106270 presented at SPE Production and Operations Symposium, Oklahoma City, OK, Mar. 31-Apr. 3, 2007. Also presented at the SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, CO, Apr. 16-18, 2007.
Abstract: This paper critically assesses the importance of various inputs that are used for a common methodology to develop a simulator model of hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The geomechanical rock properties from logs (Young's modulus, Poisson's ratio and Biot's constant) and diagnostic mini-frac injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.
The work describes the investigations using a model previously matched using both net surface pressure and microseismic/tiltmeter data. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
Woodworth, T.R. and Miskimins, J.L.: "Extrapolation of Laboratory Proppant Placement Behavior to the Field in Slickwater Fracturing Applications", paper SPE 106089 presented at SPE Hydraulic Fracturing Technology Conference, College Station, TX, Jan. 29-31, 2007.
Abstract: Low-viscosity slickwater treatments are a popular hydraulic fracturing technique in low permeability reservoirs. Slickwater treatments can provide adequate conductivity in tight gas sand operations at comparatively low costs, and wells treated with low-viscosity slickwater often produce better results than those treated with cross-linked fluids in low permeability situations. Theoretically, proppant transport is poor in low-viscosity slickwater type fluids. Improving the understanding of proppant transport capabilities of slickwater would be beneficial to many operators if the cost or performance were not endangered. Improved proppant transport would result in longer propped fracture half-lengths and more favorable conductivity.
Laboratory experiments performed by STIM-LAB, Inc.'s Proppant Consortium show proppant falls from suspension and builds a proppant mound before any form of proppant transport takes place. Clean fluid stages pumped between sand-laden stages were shown to erode proppant from the proppant mound. These results formed the basis for the development of power and bi-power laws to describe the transport. These laws and the results of the laboratory experiments were used to perform sensitivity analysis to determine the relative effects of fluid viscosity, fluid density, pump rate, proppant diameter, proppant density, proppant concentration, and fracture width on slickwater treatments in the field.
Using the power and bi-power laws, the resulting sensitivity analysis, and the laboratory observations, experimental slickwater schedules were designed and field tested. A total of five experimental slickwater fracturing treatments were performed. Production data from each experimental slickwater treatment and well were compared to offset data to determine any possible effects from improved proppant transport. Production results from the field trials, including both initial production (IP) rates and early cumulative production totals, indicate significant improvement when compared to offset wells.
Green, C.A., Barree, R.D., and Miskimins, J.L.: "Development of a Methodology for Hydraulic Fracturing Models in Tight, Massively Stacked, Lenticular Reservoirs", paper SPE 106269 presented at SPE Hydraulic Fracturing Technology Conference, College Station, TX, Jan. 29-31, 2007.
Abstract: This paper describes and critically assesses a common methodology currently used to model hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The model incorporates a unique data set from the Piceance basin, Colorado, which produces hydrocarbons from the Cretaceous-age Mesaverde formation. Initially, vertical variations in geo-mechanical rock properties (Young's modulus, Poisson's ratio and Biot's constant) were calculated from well logs. The results were then compared with previous work undertaken on the Mesaverde formation and carried out at the DOE/GRI MWX site. From this analysis, specific correlations were developed for rock properties derived from well logs on a foot-by-foot basis to be used in the hydraulic fracture model. Diagnostic mini-frac injection tests of individual sandstone reservoirs were used to confirm model inputs and develop a valid stress model.
Previous attempts to model hydraulic fracture growth in the Mesaverde have been hampered by a lack of detailed input data sets and the inability to accurately determine horizontal rock property variations. This paper outlines a method which uses micro-seismic/tiltmeter data to constrain and verify the model inputs. The resulting frac model is shown to have not only matched the fracture containment but also pressure matched the actual net surface pressure data in this extremely geologically complex area. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data required to develop such a model has been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
2006
Casas, L.A., Miskimins, J.L., Black, A.D., and Green, S.J.: "Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities", paper SPE 103617 presented at SPE Annual Technical Conference and Exhibition, San Antonio, TX, Sept. 24-27, 2006.
Abstract: The design and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e., a lower fluid pressure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from three-dimensional modeling.
Bai, M., Green, S., Casas, L.A., and Miskimins, J.L.: "3-D Simulation of Large Scale Hydraulic Fracturing Tests", paper ARMA/USRMS 06-959 presented at the American Rock Mechanics Association GoldenRocks Conference, Golden, CO, June 17-21, 2006.
Abstract: With proper scaling, the large scale laboratory hydraulic fracturing tests can be an effective way to provide parametric justification for the fracturing design. The tests can also be used to validate hydraulic fracturing models, considering the significant cost reduction via the laboratory tests in lieu of the field tests. Similarly, numerical simulation may act as a "virtual test" to imitate the laboratory test for achieving improved flexibilities at further reduced cost. In this paper, the result of numerical simulation of the hydraulic fracturing using 3-D model is presented and compared with the measurements from the large scale laboratory hydraulic fracturing tests. The excellent match between the numerical simulation and the experimental tests validates both processes. Further pressure analysis offers an in-depth study on transient fracture propagation and contrasting pressure responses based on the relative positions from the perforation, as well as offers certain validation for the zone of fluid lag near the fracture tip area.
Casas, L.A., Miskimins, J.L., Black, A., and Green, S.: "Hydraulic Fracturing Laboratory Test on a Rock with Artificial Discontinuities", paper ARMA/USRMS 06-917 presented at the American Rock Mechanics Association GoldenRocks Conference, Golden, CO, June 17-21, 2006.
Abstract: The design and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hydraulic fracture growth. A high viscosity (586 Pa.s) fluid was used in order to provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from three-dimensional modeling.
2005
Miskimins, J.L., Lopez, H. E., and Barree, R.D.: "Non-Darcy Flow in Hydraulic Fractures: Does It Really Matter?", paper SPE 96389 presented at SPE Annual Technical Conference and Exhibition, Dallas, TX, Oct. 9-12, 2005. (summary publication in March 2006 SPE Journal of Petroleum Technology).
Abstract - In recent years, non-Darcy flow has seen a significant increase in interest in the petroleum industry, especially in flow in fractures-both artificial and natural. In hydraulic fracture stimulation, non-Darcy flow can have a major impact on the reduction of a propped half-length to a considerably shorter "effective" half-length, thus lowering the well's productive capability and overall reserve recovery. These non-Darcy flow effects in propped fractures have been typically associated with high flow rates in both oil and gas wells.
This paper shows that non-Darcy flow effects have an impact on the performance of a hydraulically fractured well even at low flow rates. Although not as drastic as the effects on high flow rate wells, reductions in flow capacity of 5-30% can be realized in low rate wells. Such reductions are due solely to non-Darcy effects. When combined with other concerns, such as multiphase flow, the production reduction effects are even greater.
Development of a simple spreadsheet is provided to aid engineers in assessing the impact non-Darcy flow may have in a given situation. The spreadsheet is not intended to replace more in-depth investigation of non-Darcy flow effects but instead provides a conduit to assess the sensitivity of certain parameters in a hydraulic fracture stimulation situation.
For comparison purposes, results of the loss in long-term dynamic conductivity on well performance and cumulative gas recovery over time in low permeability reservoirs are also presented. These calculations were performed using dynamic conductivity loss calculations coupled with a transient gas reservoir simulator. These results showed that for the cases examined, non-Darcy effects could reduce cumulative gas production by up to 18.1% over a ten-year period.