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
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.
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.
The November issue of JPT quotes the views of Mary Van Domelen, senior engineering advisor at Performance Technologies, given in her presentation “The Pros and Cons of Vertical Integration” in shale gas-related operations. All her examples of current activity are in the realm of the vertical with the operator and a service company offering fracturing and other drilling or completion services. Her presentation was part of the SPE Liquids-Rich Basins Conference, held in September 2013 in Midland, Texas. Interestingly, both dry and wet gas can benefit immensely from a different form of vertical integration provided certain new technologies take hold. This is a vertical involving the producer and a service that monetizes low-value portions of fluids in unique ways.
Today, almost all the profit is in the wet gas component. But a subplot is that ethane usually makes up nearly half the volume of natural gas liquids (NGLs). Unlike the bigger molecules, such as propane and butane, ethane has no direct use until cracked to make ethylene. Thirty-three of the 36 crackers in the United States are located on the Gulf Coast, about 1,200 miles from the Marcellus shale in Pennsylvania. Consequently, there is an ethane glut, resulting in low prices. Dow Chemical’s David Bem reported in December that ethane dropped to natural gas price levels in 2013 and had begun to track with it (Fig. 1). This would be a windfall for ethylene producers except that the crackers are located at a distance.
Local cracking seemed to be where matters were headed. However, early in November 2013, Shell announced that it had shelved plans to build a cracker in Pennsylvania. This leaves the ethane stranded absent a pipeline to transport it down to the Gulf of Mexico. A better solution would be small crackers, 50 to 100 times smaller than conventional plants, distributed close to the production. Development is in progress to realize this “GTL Lite” concept. The definition of liquid in this context is broad: It could be any high-value liquid, not just diesel that traditionally comes from larger GTL plants.
Security of supply is much simpler with small units, particularly because a lot of the producers themselves are small. And it is immensely simpler if the producer and cracking process owner are vertically integrated. Even long-term pricing would not be a contractual hurdle. But true vertical integration is hampered by the fact that the producer has no domain understanding of the other area, which is essentially downstream in character.
For unconventional hydrocarbons, including heavy oil, a blurring of the upstream, midstream, and downstream sectors is occurring. Small footprint processing, when commonly available, will only serve to hasten this blurring.
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 paper was prepared for presentation at the 1998 SPE Gas Technology Symposium held in Calgary, Alberta, Canada, 15-18 March 1998.