Li, Bingjian (Schlumberger Oil Field Services) | Chen, Yong-Hua (Southwestern Energy, Woodland, USA) | Gawankar, Kiran (Schlumberger-Doll Research) | Miller, Camron K. (Schlumberger Oil Field Services) | Xu, Weixin (Schlumberger Oil Field Services) | Laronga, Rob J. (Schlumberger Oil Field Services) | Omeragic, Dzevat (Southwestern Energy, Woodland, USA)
Distinguishing open natural fractures from healed fractures has been a significant challenge in shale formations drilled with oil-based mud. Ultrasonic imaging tools can locate open fractures, but such data is seldom acquired due to concerns related to the effects of heavy mud and, in high-angle wells, operational efficiency and tool eccentralization. Until now, the microelectrical image tools in the market were not capable of differentiating open fractures from healed fractures in oil-based mud.
A new, high-definition oil-based mud microelectrical imager has been deployed that operates at high frequencies and provides images with high borehole coverage. This new tool can identify natural fractures, sub-seismic faults, and other geological features in the reservoirs. In addition to high-resolution images of formation resistivity, an advanced inversion processing can be applied to generate resolution-matched images of the quantified standoff between each sensor in the array and the borehole wall. Such standoff images are of special value for differentiating open fractures from healed fractures. The use of these standoff images are presented in several recent case studies from U.S. shale plays. In the first case study from a pilot shale well in the northeast, natural fractures are identified on the new microelectrical imager and then further interpreted as open, partially open or healed fractures based on the inverted standoff images. Such open fracture interpretation has been validated by ultrasonic image data from the same well. In the second case study from an Eagle Ford Shale lateral in south Texas, both natural fractures and sub-seismic faults were detected. Interestingly, one of the interpreted open faults based on standoff images was even evident on dynamic pressure data in a monitoring well nearby during the stimulation process.
Natural fractures can impact the shale reservoir quality, completion quality, or both, depending on the fracture types and intensity. Therefore, it is beneficial to have a reliable dataset to sort fractures by their type: open, partially open and healed.
The Weir zone in West Virginia is comprised of three separate sandstones that are Lower Mississippian in age and fall within the Price formation. The Weir sandstone of southeastern West Virginia is characterized by a near shore fluvial dominated delta front environment causing a gas bearing reservoir. Stimulation of the Weir sandstones is necessary for economic recovery of gas reserves.
This study provides background on the Upper Weir sandstone of McDowell, Mercer and Wyoming counties of West Virginia and focuses on historical stimulation treatments involving parameters such as amount of proppant and injection rate influencing the Estimated Ultimate Recovery (EUR). An extensive database containing geology, completion, stimulation and production data from the Upper Weir sandstone in southeastern West Virginia was utilized in this study. Single zone completion and adequate production history, greater than 12 months, were the criteria for well selection from the database of Weir wells in the southeastern West Virginia area. The total proppant placed was the major contributing factor in the resultant EUR. Increasing the total proppant not only increases the EUR but also decreases the number of wells to effectively drain the reservoir. From the results, economic analysis was completed to provide guidelines to achieve economic recovery from the Upper Weir sandstone in southeastern West Virginia.
With the increased use of 3-D fracture simulators, the need for accurate and affordable formation stress tests has arose. One of the main factors in keeping the test cost down is conducting the stress test with water. In most formations, the stress gradient is high enough (i.e. >0.433 psi/ft) that water can be used, but there are many formations (Berea, Weir, Devonian Shale) that have stress gradients lower than 0.433 psi/ft. When this situation occurs, the hydrostatic pressure of the water can fracture the formation and the well goes on vacuum. This leads to problems establishing constant injection rates and pressures that are usually obtained before monitoring pressure falloff. In the past, formations with low stress gradients used nitrogen for the test fluid, thus keeping the hydrostatic pressure below frac gradient. This method works but is extremely cost prohibited.
This paper explains the problems that can occur when testing low stress gradient formations, and procedures that can be used to gain accurate formation stress profiles using water and a downhole shutoff tool with equalizing ports.
This reference paper reviews and describes 15 techniques for determining hydraulic fracture azimuth. The techniques described are categorized into core-based, bore- hole-based, near-wellbore, and regional geologic indicators that can be used to predict or measure hydraulic fracture azimuth. The core based methods include: 1) circumferential velocity anisotropy, 2) anelastic strain recovery, 3) differential strain curve analysis, 4) axial point load tests, 5) petrographic examination of micro-cracks, 6) overcoring of archived core, 7) drilling-induced fractures in core, and 8) direct observation of over-cored open-hole stress test fractures. The borehole based techniques include: 9) borehole breakouts, 10) borehole deformation, 11) borehole imaging of drilling-induced fractures, and 12) directional gamma ray logging. The near-wellbore techniques provided data on the orientation of the fracture induced during an actual fracture treatment and include: 13) microseismiclogging and 14) earth tilt surveys. Finally there are the geologic indicators (Method 15) including earthquake focal mechanisms, fault slip data, surface mapping of neotectonic joints, and volcanic vent alignment. These regional data have been compiled for the World Stress Mapping Project and many maps are available that can be used as a first approximation of stress direction.
Experience has shown that the more techniques that can be used in a single well or field, the more reliable the result. The concept or theoretical basis for each technique as well as the benefits and limitations of the techniques are described.
This paper summarizes the techniques that can be used to determine maximum horizontal stress direction for oil and gas field development. Maximum horizontal stress direction is important for patterning hydraulically-fractured field development wells to optimally drain a reservoir, patterning waterflood wells to optimize recovery, and determining the natural fracture set with the greatest production capacity since the natural fractures that parallel maximum horizontal stress are often the most productive.
The techniques for determining subsurface stress direction described in this report are divided into core-based techniques, borehole-based techniques, near-wellbore techniques, and regional geologic indicators.
In an effort to better understand the geologic and engineering factors that explain the production performance of the tight Clinton sandstone of Eastern Ohio, logs, completion data, and production performance records were evaluated for a number of production performance records were evaluated for a number of Clinton sandstone wells in east central Ohio.
The wells were divided into low slope (linear) and high slope (radial) groups based on plots of log cumulative production versus log time. The distributions of expected recoveries from these two groups of wells were compared using the chi square and Pearson's P-M correlations, and were found to be significantly different. The linear wells had a median expected ultimate production of less than 20 MMcf (5.7 x 10(5) m3) while the radial group had a median of more than 50 MMcf (1.4 x 10(6) m3). Some of the wells tended to be located in contiguous trend areas. The distance to the drainage boundary was also calculated for the linear and radial wells. The median length for the linear wells is about 500 feet (150 m) while the median radius for the radial wells is about 2,000 feet (600 m).
The intent of this paper is to provide industry with a methodology that can be used to calculate reservoir parameters, such as size and geometry, which are important in designing stimulations and in estimating reserves.