The pipeline system that conveys the individual-well production or that of a group of wells from a central facility to a central system or terminal location is a gathering pipeline. Generally, the gathering pipeline system is a series of pipelines that flow from the well production facilities in a producing field to a gathering "trunk" pipeline. Gathering systems typically require small-diameter pipe that runs over relatively short distances. The branch lateral lines commonly are 2 to 8 in. Gathering systems should be designed to minimize pressure drop without having to use large-diameter pipe or require mechanical pressure-elevation equipment (pumps for liquid and compressors for gas) to move the fluid volume. For natural-gas gathering lines, the Weymouth equation can be used to size the pipe. "Cross-country" transmission pipelines will collect the product from many "supply" sources and "deliver" to one or more end users. Transmission pipelines will generally require much larger pipe than gathering systems. Transmission systems normally are designed for long distances and will require pressure-boosting equipment along the route. Many factors must be considered when designing, building, and operating a pipeline system. Once the basic pipe ID is determined using the applicable flow formula, the other significant design parameters must be addressed. For U.S. applications, gathering, transmission and distribution pipelines are governed by regulations and laws that are nationally administered by the U.S. Dept. of Transportation (DOT).
Hydraulic fracturing stimulation designs are moving towards tighter spaced clusters, longer stage length, and more proppant volumes. However, effectively evaluating the hydraulic fracturing stimulation efficiency remains a challenge. Distributed fiber optic sensing, which includes Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS), can continuously monitor the hydraulic fracturing stimulation downhole and be compared with other monitoring technology such as microseismic. The DAS and DTS data, when integrated with the microseismic, highlight processes relevant to the completion design and allow for a better understanding and interpretation of each dataset.
This paper outlines a workflow to improve processing and interpretation of DAS and DTS data. In addition, an estimate of the slurry distribution can be made. These methods will be demonstrated for a horizontal Wolfcamp well in the Permian Basin. Here we compare key aspects of the microseismic, DAS, and DTS results in several fracture stages to understand the downhole geomechanical processes. In order to interpret the DTS data a thermal model is developed (using DTS data) to simulate the temperature behavior after pumping has ceased. A slurry distribution is obtained by matching the simulated temperature with the measured temperature from DTS. In addition, the DAS data signal is studied in the frequency domain and the dominant frequencies are identified that are mostly related to fluid flow and to reduce the background noise. This time frequency analysis enhances the ability to monitor and optimize well treatments.
After reducing the background noise, the acoustic intensity is correlated to the slurry distribution. The fluid distribution data from DAS and DTS are compared with the microseismic and near field strain to better understand the completion processes. We utilized fiber optic microseismic to better understand and compare it to conventional microseismic.
Finally, we highlight the dynamics of strain and microseismic signature as fluid moves from an offset well completion into the prior stimulated fiber well to better understand the reservoir and far field effects of the completion.
Meek, Robert (Pioneer Natural Resources) | Hull, Robert (Pioneer Natural Resources) | Woller, Kevin (Pioneer Natural Resources) | Wright, Brian (Pioneer Natural Resources) | Martin, Mike (Pioneer Natural Resources) | Bello, Hector (Pioneer Natural Resources) | Bailey, James (VSProwess)
Fluid and proppant are injected into a shale reservoir during a hydraulic stimulation, causing changes in rock properties. Over time fluid and pressure bleed off into the reservoir causing further changes. We measured these changes as well as the height of the hydraulic fracture at 1.5-hour intervals using single source point seismic recordings.
A distributed acoustic sensor (DAS) and pressure gauges were installed in a vertical well to monitor the hydraulic stimulation of several horizontal wells. In the vertical well we conducted microseismic recordings using geophones, tiltmeter measurements, strain measurements from DAS, distributed temperature sensor (DTS) readings, and several monitor walk-away time-lapse VSPs (vertical seismic profiles) along with repeated single offset source VSPs. The single source VSP was acquired every 1.5 hours over three days and was oriented so that the direct arrival passed through a single stage in one of the horizontal wells. We estimated the height of the p-wave velocity change due to the hydraulic fracture by measuring travel time changes in the direct arrival. The changes in height and velocity due to the deflation of the pressure over time was also measured. The fracture height was comparable with estimates from microseismic, DAS, and tiltmeters.
In this paper we describe a method to better highlight the geometry of altered rock from a hydraulic stimulation within the Spraberry Formation of the Midland Basin in West Texas. Pioneer Natural Resources is currently developing significant unconventional resources within the basin and methods like those noted here enable an understanding of fracture geometry and well interaction during hydraulic stimulation that are important in developing unconventional resources. By acquiring several different types of data, a more accurate picture of the fracturing process can be observed and field development and geomechanical models can be adjusted accordingly. The use of DAS/DTS fiber allows for a very cost-effective and rapid acquisition of vertical seismic profiles. Pioneer has used time-lapse, fiber-based VSPs in the past with good results (Meek, 2017). Meadows (1994) observed changes in travel time during a hydraulic fracture using geophones. Recently, Byerley et al (2018) described a time-lapse experiment to monitor a hydraulic fracture during each stage into a horizontal fiber. They observed that the time delay diminished over a few days. It is thought that this time-delay was caused by fractures opening during the completion and decreasing the velocity around the well bore. Fluid and pressure leaking off over time then results in an increase in velocity of the altered rock. Understanding this pressure build up and later diffusion is important to understanding the interaction of offset well fracture stages which may influence well spacing decisions. It is also useful in determining how long adjacent wells that were shut in during completion can be placed back on production. Beyond the use of microseismic, imaging the hydraulic completion from surface geophysical techniques has been challenging. As a result we have begun to utilize subsurface imaging techniques like VSPs to gain further insight into the dynamics of the stimulation. Here we demonstrate the usefulness of the VSP by recording data into the vertical fiber only. Unfortunately, with a horizontal fiber it is difficult to obtain the height and width of the fracture using reflection energy. Experiments are currently being conducted using downward continuation of reflection energy from horizontal fibers to image around the well bore (Fuller, 2019).
Temperature-based production logging inversion for unconventional horizontal wells are highly sensitive to the accuracy of the temperature measurements. In order to get reliable results, the systematic bias of the measurements has to be smaller than 0.05 °F. DTS measurements suffer the error due to differential attenuation and instrument instability, which cannot be eliminated by averaging a long period of measurements and can potentially bias the production logging inversion. We developed a calibration workflow for double-ended DTS systems that reduces the systematic bias in the measurement. We attack the differential attenuation bias by comparing and averaging the measurements from the down-going and up-going fiber, avoiding or correcting locations where fibers are spliced or damaged. The offset bias due to instrument instability is calibrated using borehole gauge measurement and the DTS data itself. This calibration is performed in the frequency domain to improve the results. The calibrated results show significant improvement in the quality and accuracy of the DTS data. This work provides a detailed analysis and discussion on the error and bias in the DTS measurement. The public understanding of the limitation of the DTS system helps to push the service providers to improve their instrument design and calibration workflow. The calibration workflow presented here significantly improved the DTS data quality for several real cases.
Temperature logging has a long history for production and injection monitoring (e.g. Ramey Jr., 1962; Curtis and Witterholt, 1973). The recent development of the fiber-optic sensing technology, especially Distributed Temperature Sensing (DTS), makes borehole temperature measurements much more accessible and cost efficient. DTS measures absolute temperature along an optic fiber that can be several miles long, with a spatial resolution around 1 foot and temporal sampling interval between 1 second to several minutes. Many new applications have been developed using DTS in the oil industry, including hydraulic fracturing monitoring (e.g. Sierra et al., 2008; Holley et al., 2010), well integrity diagnostic (e.g. Gonzalez et al., 2012), production logging (e.g. Ouyang and Belanger, 2004; Jin et al., 2019), etc.
This paper is a companion to URTeC 2670034, “Sampling a Stimulated Rock Volume: An Eagle Ford Example.” That paper detailed the nature of the stimulated rock volume adjacent to a hydraulically fractured horizontal well. It demonstrated that hydraulic fractures are far reaching and abundant but quite variably distributed spatially; the presence of well propped fractures beyond 100 feet of the stimulated well appeared negligible.
The present paper reconciles the production performance of the central pilot well with far-field pressure monitor data to characterize the drained rock volume (DRV). Central to the stimulated reservoir description is the integration of data from core, image logs, proppant tracer, distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and pressure which shows that not all hydraulic fractures are created equal. Principal and secondary hydraulic fractures are identified based on the correlation between image log interpreted fracture aperture and the far-field pressure data. Analysis of distributed temperature data during the completion and warm back period is furthermore used to infer fracture connectivity to the well. A highly fractured near well region between clusters is concluded. A novel data-driven reservoir model is constructed wherein the key interpretations are consistently integrated. Production, bottom hole pressure, and far-field pressure data from 14 pressure monitoring stations are history matched. A heterogeneous drained rock volume is predicted. The integrated model is compared to common production history matched planar fracture models to assess the potential impacts on cluster spacing, well spacing, and well stacking decisions.
In 2017 ConocoPhillips reported (Raterman, et al., 2018) on a pilot conducted in the Eagle Ford (EF) shale that was internally referred to as the “SRV pilot”. The original paper dealt primarily with the execution of the pilot and the attendant description of hydraulic and natural fractures within the
Binder, Gary (Colorado School of Mines) | Titov, Aleksei (Colorado School of Mines) | Tamayo, Diana (Colorado School of Mines) | Simmons, James (Colorado School of Mines) | Tura, Ali (Colorado School of Mines) | Byerley, Grant (Apache Corporation) | Monk, David (Apache Corporation)
In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a time-lapse vertical seismic profiling (VSP) survey before and after each of 78 hydraulic fracturing stages. The goal of the survey was to more continuously monitor the evolution of stimulated rock throughout the treatment of the well. From two vibroseis source locations at the surface, time shifts of P-waves were observed along the well that decayed almost completely by the end of the treatment. A shadowing effect in the time shifts was observed that enables the height of the stimulated rock volume to be estimated. Using full wavefield modeling, the distribution of time shifts is well described by an equivalent medium model of vertical fractures that close as pressure declines due to fluid leak-off. Converted P to S waves were also observed to scatter off stimulated rock near some stages as confirmed with full wavefield modeling. The signal-to-noise ratio is a limitation of the current dataset, but recent improvements in DAS technology can enable stage-by-stage monitoring of the stimulated rock height, fracture compliance, and decay time as a well is completed.
Distributed Acoustic Sensing (DAS) has opened new possibilities for seismic monitoring of unconventional reservoirs. Using a laser interrogator to launch light pulses down a fiber optic cable, dynamic strain changes can be sampled along the cable from the phase shift of light backscattered to the interrogator (Hartog, 2017). Since the fiber optic cable can be permanently cemented outside the casing in a borehole, highly repeatable vertical seismic profiling (VSP) surveys can be acquired frequently without costly wireline geophone deployments that interfere with well treatment activities (Mateeva et al., 2017; Meek et al., 2017).
As described by Byerley et al., 2018, a unique interstage DAS VSP survey was conducted in 2017 during the stimulation of a horizontal well targeting the Wolfcamp formation in the Midland Basin, Texas. Using two vibroseis source locations offset about 1 mile from the heel and toe of the well, DAS data was acquired in the treatment well before and after each of 78 hydraulic fracturing stages. At the expense of fewer source locations, this type of acquisition allows the evolution of the stimulated rock volume (SRV) to be monitored on a stage-by-stage basis as the well is treated.