This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
Numerous studies on unconventional shale well production data have shown that downhole pressure fluctuations can exceed 300 psig during a slugging period. Such pressure fluctuation will result in very high drawdown and could lead to near-wellbore formation damage when the rock failure criterion was met. An engineering workflow was developed to investigate the impact of multiphase slugging events on cemented casing plug and perforation (CCPP)and open hole sliding sleeves (OHSS) completions. Based on transient pressure analysis and geomechanical evaluation, safety operational envelope was generated to minimize the risk of formation damage due to slugging behavior.
In this study, a dynamic multiphase flow simulator was used to predict the pressure amplitude and frequency during the slugging events in both a CCPP and OHSS completion configuration. The results from the simulation were then incorporated into a geomechanical model to analyze and identify potential hydraulic fracture closure and formation damage concerns, which can compromise well performance.
The results from this study show that OHSS completion is more vulnerable to damage during the downhole slugging period than a CCPP completion. However, severe formation and fracture damage could occur during downhole slugging for CCPP well if the well is operated outside the safety operational envelope. Results from the two case studies led to the conclusion that it is crucial to consider the effect of downhole slugging on near-wellbore fracture and formation integrity to avoid permanent and irreversible damage.
We assert that a classification of gas flow regimes in shales that is widely accepted in the petroleum industry, may be inconsistent with the physics of high-pressure gas flow in capillaries. This classification follows from the 1946 work by
In the small-scale, low-velocity flows of gases, failure of the standard Navier-Stokes description (the standard Darcy law in petroleum engineering) can be quantified by the Knudsen number, ratio of the mean free path, λ, of gas molecules at the reservoir pressure and temperature to the characteristic pore radius,
For example, in Barnett mudrocks, naturally occurring pores are predominantly associated with organic matter and pyrite framboids. In organic matter, the median pore length is 100 nm,
The generally accepted "Knudsen-diffusion" in shales is based on a mistranslation of the flow physics and may give theoretically unsound predictions of the increased permeability of shales to gas flow. This increase of permeability is real, and it comes from the micropores, fine-scale microfractures and cracks. The nanopores in shales provide gas storage by sorption and capillary condensation of heavier gas components. In the smallest nanopores even methane molecules are increasingly ordered and resemble more liquid than gas. These nanopores feed the macroscopic flow paths in ways that are not captured well by the generally accepted equations.
Kavousi, Payam (West Virginia University) | Carr, Timothy (West Virginia University) | Wilson, Thomas (West Virginia University) | Amini, Shohreh (West Virginia University) | Wilson, Collin (Schlumberger) | Thomas, Mandy (Schlumberger) | MacPhail, Keith (Schlumberger) | Crandall, Dustin (National Energy Technology Laboratory, US Department of Energy) | Carney, BJ (Northeast Natural Energy LLC) | Costello, Ian (Northeast Natural Energy LLC) | Hewitt, Jay (Northeast Natural Energy LLC)
Distributed acoustic sensing (DAS) technology also known as distributed vibration sensing (DVS) uses optical fibers to measure the dynamic strain at all points along the fiber (Parker et al, 2014). The DAS senses the vibration in the local environment around the fiber and provides a measure of the relative strain of the optical fiber. This remote sensing technique has provided unparalleled acoustic sampling from the subsurface during hydraulic fracturing of the horizontal MIP-3H well drilled in Marcellus Shale near Morgantown, WV. We will show that the energy of the extracted phase of DAS data (hDVS) has a strong negative correlation with natural fracture intensity P32. The hydrofracking stages with lower P32 show a higher DAS phase energy and vice versa. In addition, we will evaluate the correlation between DAS phase energy, microseismic energy, and injection energy during the hydrofracking in MIP-3H. DAS phase energy is linearly correlated with injection energy. The calculated microseismic energies, which are less than 0.1% of the injection energies, do not show a significant correlation with either DAS phase energy or injection energy. The negative correlation between P32 and either DAS phase energy or injection energy suggests less vibration in zones that are more naturally fractured. Numerous observed fractures from wireline image logs are resistive (healed), and appear to significantly control the hydrofracking efficiency in MIP-3H.
Presentation Date: Tuesday, September 26, 2017
Start Time: 10:35 AM
Presentation Type: ORAL
Microseismic monitoring and data from distributed acoustic sensing (DAS) can yield two independent measurements of the strain response to hydraulic stimulation of geologic formations. Microseismic monitoring provides a map of where, when and how the rock has catastrophically failed. DAS measurements from an optical fiber cable embedded in a horizontal well, adjacent to the stimulated well, can determine the relative strain response of the geologic formation that is in contact with the well bore. The strain response is not limited to rock failure and can respond to both dynamic and static deformation. However, DAS data are limited to the line defined by the spatial coordinates of the optical fiber cable and, in this configuration, cannot give a three-dimensional view of the strain response. By utilizing both DAS and microseismic data simultaneously and viewing both datasets in the same coordinate system, a more complete understanding of the rock response to hydraulic stimulation can be obtained.
Presentation Date: Wednesday, September 27, 2017
Start Time: 3:05 PM
Presentation Type: ORAL
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.
Figure 1—Eight pads with 192 microelectrodes can be applied independently to the borehole wall, ensuring optimum-quality measurements even in deviated wells and poor hole conditions, and enabling borehole imaging while being run into the hole. To estimate reserves, optimize well recovery, and place future development wells more accurately, operators require increasingly detailed understanding of complex oil and gas reservoirs. High-resolution geological data from the borehole—core samples and wireline microresistivity images—are essential to fully characterize reservoir architecture, guide and constrain reservoir models, and make timely decisions with precision and confidence. In high-cost deepwater environments, exploration teams need to interpret a wide variety of sedimentary facies. Reservoirs often consist of thinly laminated sands or channels, which demand high-definition methods for visualization and interpretation.
To estimate reserves, optimize well recovery, and place future development wells more accurately, operators require increasingly detailed understanding of complex oil and gas reservoirs. High-resolution geological data from the borehole— core samples and wireline microresistivity images—are essential to fully characterize reservoir architecture, guide and constrain reservoir models, and make timely decisions with precision and confidence.
In unconventional resource plays, for example, geologists need to observe complex natural fracture systems, measure fracture density and direction, determine in-situ stresses, and calculate pressures required to initiate and propagate optimal hydraulic fracturing. In high-cost deepwater environments, exploration teams need to interpret a wide variety of sedimentary facies. Reservoirs often consist of thinly laminated sands or channels, which demand high-definition methods for visualization and interpretation. Typically, deepwater formations exhibit very low resistivities— from 1 ohm-m in shales to as low as 0.2 ohm-m in water-bearing sands.
Operators often use whole cores to identify subtle sedimentary facies, but cores can be expensive and time-consuming to acquire. Thus, core samples are usually obtained only in select wells and in the most critical intervals. The resulting lack of geological detail can adversely affect reservoir analysis, interpretation, and modeling.
On the other hand, microelectrical borehole images can be acquired continuously over the openhole interval at any depth or in any formation, with relative ease. Until recently, high-definition borehole imaging has been possible only in electrically conductive water-based muds (WBM). However, most deepwater wells and many unconventional shale wells today are drilled with high-performance, nonconductive oil-based muds (OBM).
Legacy OBM borehole imaging tools, which were introduced in the last decade, are a significant technical advancement over the preceding dipmeter tools but still exhibit certain limitations. For example, spatial image resolution in OBM is nowhere near the quality obtained from WBM imagers. The lack of circumferential coverage of the borehole leaves large gaps that must be filled by inference.
In multi-fractured horizontal wells, the wellbore is segmented into stages that are stimulated separately. This segmentation is traditionally geometrically based on a specific stage length (“geometric staging”); which is usually determined by trial and error including cost and production history considerations. However, this approach does not take geological and geomechanical properties into account. An alternative method for staging (“engineered staging”) uses these properties to determine the wellbore segmentation by grouping intervals with similar rock properties together; theoretically promoting a higher percentage of stimulated clusters and subsequently better production. This alternative method is not commonly used as data acquisition can be costly for a large group of wells.
In Pennsylvania, two pairs of wells were completed in order to understand the added value of engineered staging design. In one of them, a comprehensive suite of openhole logs was run in the horizontal leg of a dry gas well. The staging was then designed according to the measured rock properties and the well was stimulated using slickwater with plug and perf. Finally, a production log was run in the well after a year in order to determine the downhole contribution of each stage and cluster. After 400 days of production, the well cumulative production outperforms its offset with geometric staging by around 5 to 7%, potentially attributable to the engineered design but still within the expected statistical regional deviation between wells. Long term impact is yet to be determined.
In the other pair, no openhole log other than MWD Gamma-ray was run. However properties were projected from a nearby vertical pilot hole with logs onto the horizontal section of a well which was then completed using the engineered staging method. Here again production figures after a year are showing a potential benefit; but this time without the cost of data acquisition in the lateral.
This paper describes the process that was applied to achieve the engineered staging of these wells. It details the initial geological and geomechanical data acquisition or projection; then describes the design of the hydraulic fracturing engineered staging and finally discusses the performance of the wells.
IntroductionAs the number of wells drilled in the Utica Shale play continues to grow, maximizing well performance by optimizing wellbore orientation, landing point and proper completion strategy are vital to the success of this play. This paper will focus on wellbore orientation. Most of the wellbores drilled in the Ordovician Point Pleasant member of the Lower Utica Formation, the target landing zone in the play, have used an orientation similar to the shallower Devonian Marcellus wells (Figure 1). In the Marcellus, this orientation is used to improve the effectiveness of the fracturing process by exploiting the in-situ rock stress. Orienting the wellbore properly with respect to the principal horizontal stress direction helps to keep the fractures induced by the hydraulic fracturing process from closing. In the Devonian Marcellus play, deviating from the preferred wellbore orientation negatively impacts well production. Wellbore image data, sonic anisotropy, and microseismic are tools used to determine the direction of the principal stress and in turn, the orientation of the horizontal wellbore.