This paper describes the development and capabilities of a novel and unique tool that interfaces a hydraulic fracture model and a reservoir simulator. This new tool is another step in improving both the efficiency and consistency of connecting hydraulic fracture engineering and reservoir engineering.

The typical way to model hydraulically fractured wells in 3D reservoir simulators is to approximate the fracture behavior with a modified skin or Productivity Index (PI). Neither method captures all the important physics of flow into and through the fracture. This becomes even more critical in cases of multiphase flow and multi-layered reservoirs. Modeling the cleanup phase following hydraulic fracture treatments can be very important in tight gas reservoirs, and this also requires a more detailed simulation of the fracture. Realistic modeling of horizontal wells with multiple hydraulic fractures is another capability that is needed in the industry. This capability requires more than an approximate description of the fracture(s) in the reservoir simulation model.

The paper details the acquisition of detailed core and pressure data and the subsequent reservoir modeling in the Ozona Gas Field, Crockett County, Texas. The Canyon formation is the focus of the study and consists of complex turbidite sands characterized by numerous lenticular gas bearing members. The sands cannot be characterized using indirect measurements (logs) and no reliable porosity-permeability relationship could be developed. The reservoir simulation results illustrate the problems associated with interpreting typical pressure and production data in tight gas sands and details procedures to identify incremental reserves. Reservoir layering was represented by five model layers and layer permeabilities were estimated based on statistical distributions from core measurements.

This paper illustrates a comprehensive and economical approach to the application of reservoir data to optimize stimulation designs. The paper documents the selective application of in situ stress tests and dipole sonic logs to provide accurate stress profiles that can be used in concert with standard log and mini-fracture data to improve stimulation designs.

Measured stress data on 3 wells were used to calibrate open-hole logs to provide an estimate of stress profiles throughout a 300 square mile area of the Moxa Arch. Dipole sonic log-derived stress profiles were correlated to measured stress data. Calibrated stress profiles from dipole sonic logs and the measured stress data were then used to develop a correlation between gamma-ray logs and in situ stress. The log-based stress data was improved with the addition of over 50 mini-fracture tests. The combination of selected stress measurements, dipole sonic logs, and mini-fracture treatments resulted in optimized stimulation designs and cost savings of over $100,000 per well.

This paper details the application of static tubing pressure measurements and on-site fracture modeling on over 70 wells in the Moxa Arch and Wamsutter areas in the Green River Basin, Wyoming. Specific examples illustrating the field procedures that evolved during a 2-year development program are presented, including on-site analysis of mini-fracture treatments, pad optimization, and treatment evaluation. Field applications include foamed and water based fluids in low and moderate permeability Frontier and Mesaverde gas sands. Bottom-hole pressure (BHP) measurements in all 70-plus treatments were obtained using a static tubing string, eliminating the inaccuracy of surface estimated BHP. Field data illustrate large variations in friction pressures that occur during many treatments which may lead to erroneous interpretations and premature job termination.

The quality of the data coupled with on-site three dimensional (3D) fracture modeling allowed field engineers to evaluate minifrac data and optimize pad volumes within 30 minutes. On-site modeling of the mini-frac data eliminated the need to measure fracture closure time which requires long shut-ins for many tight gas formations. This procedure includes the mini-frac volume in the pad volume, decreasing mini-frac costs and job delays.

A comparison of hydraulic fracture performance during the initial development of the Moxa Arch Frontier sandstone in southwestern Wyoming (1975-85) through infill development in 1989-91 (320 acre spacing) and 1992 (160 acre spacing) is presented. The evaluation includes 3D hydraulic fracture modeling of reflected bottom hole pressures measured on 36 wells completed in 1992. In addition, in situ stress test results from two wells are integrated with 3D fracture modeling and reservoir simulation of post-fracture well performance to evaluate the evolution of fracture treatments over 17 years of development.

The results from over 200 fracturing treatments were used to quantify the effect of treating fluid and proppant type on well performance. Detailed 3D fracture modeling illustrates the effects of in situ stress and leakoff properties on fracture geometry. The results from 3D fracture modeling of 33 minifracs indicates vastly different fluid loss behavior from well-to-well and a variation of in situ stress within the Moxa Arch. The performance of 1992 infill wells stimulated with guar-based gels (borate and zirconium crosslinked) and sand is similar to initial development wells stimulated using guar-based crosslinked polymers and sand; however, the performance of 1989-91 infill wells stimulated using CO2 foam and intermediate strength ceramic proppants (ISP) did not perform as well as the waterbased fluids and sand treatments. Fracturing net pressure data are presented that illustrate excess pressures due to "proppant effects" and breakdown of stress barriers during fracturing that occurs in many treatments.

A case history of the Moxa Arch in southwestern Wyoming details the initial development on 640 acre spacing in 1977 through 1982 and the results of subsequent infill wells drilled from 1989 to 1992. The engineering evaluation includes an integration of 3D hydraulic fracture modeling and reservoir simulation with petrophysical and geological studies.

The study indicates that the Moxa Arch Frontier Formation is very heterogeneous with permeabilities ranging from 0.001 mD to more that 0.1 mD. The productive sand thicknesses vary from less than 10 ft to over 70 ft. Effective drainage areas range from over 640 acres to less than 100 acres, with ultimate gas recoveries estimated from less than 1 BCFG to over 5 BCFG. Reservoir and hydraulic fracture modeling indicate that infill drilling on 160 acre spacing (within a portion of the Moxa Arch) would increase reserves by 68% when compared to reserves for 320 acre spacing. Results from new CO2 foam/ISP stimulations did not show significant improvement compared to early water-based fluid and sand treatments.