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Koperna, George J (Advanced Resources International, Inc.) | Murray, Brett L (Advanced Resources International, Inc.) | Riestenberg, David E (Advanced Resources International, Inc.) | Carpenter, Steven M (Enhanced Oil Recovery Institute)
Abstract While every tight oil play is unique, there are lessons that can be transferred from one play to another to improve the efficiency and pace of production operations and development. These improvements may not fit precisely in every basin or play but generally hold to themes that can be tested against and built upon. Themes such as the quantity of proppant, longer lateral length, or the number of stages can be directly tied to increased productivity. However, there are diminishing returns on these investment activities for which each operator, within a given play, will be required to identify and mitigate against. This is especially true as the industry steps in and begins developing new tight oil plays. In their nascent stages, these plays may have limited well penetrations and, as a result, limited geological and performance data from which to extrapolate. Pulling together an understanding of where the industry currently resides in terms of how to exploit these resources can provide a boost in terms of working towards greatly improved well completions. In 2019, the US EIA estimated that nearly 8 million barrels of oil per day were produced from tight oil reservoirs in the United States (US EIA, 2020). This represents over 60% of the domestic crude production, originating from multiple reservoirs in the Permian Basin (TX) as well as the Bakken (MT, ND), Eagle Ford (TX), Niobrara (CO, WY), and Anadarko Basin (OK) formations, among others. As such, there are 1,000s of wells across these numerous tight oil plays that can relate an informative story. To build this story, the interplay of geology, well spacing, lateral length, and stimulation, all critical to economic success, will be explored. This paper proposes to look back at these mature tight oil (and gas) basins and bring forth an understanding of what lessons can be applied to the emerging Powder River Basin tight oil reservoirs (Mowry and the Turner/Frontier). The authors will delve into the four broad topics of geology, well spacing, lateral length, and stimulation, highlighting case studies to demonstrate those lessons from established tight oil plays that will underpin planned activities at a Field Laboratory Test Site in the southern Powder River Basin.
Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.
Abstract This paper reviews the diagnostic data from vertical wells where operators targeted Burkett, Hamilton and Marcellus Shales and other deeper unconventional shale or tight gas reservoirs with vertical wells between the years 2006-2013. The learnings are then translated for their applicability in horizontal development wells. Its purpose is to deliver a better perception of fracture geometry and interactions between payzones that are separated by potential fracture barriers. Multiple vertical wells employed the use of diagnostics in the form of proppant tracer, production logging and post-fracture temperature surveys to provide an improved understanding of hydraulic fracture and propped fracture height and the formations that serve as hydraulic fracture barriers. Completions variables such as treating rates, proppant volumes, perforation designs and frac fluid systems are examined to determine how they relate to propped fracture height growth. In the majority of the logs reviewed, the proppant was contained to the perforated interval or just above and below. Some wells did have extensive proppant height growth. However, in most of those cases, the propped fracture height was the result of poor cement bonding, multiple fractured intervals growing towards one another and frac plug failures. As expected, hydraulic fracture height is typically significantly higher than the proppant height. Few vertical wells showed evidence of proppant connecting the Marcellus and Burkett zones. Formations acting as fracture barriers did not respond to many of the completions variables. Large treatment volumes, up to 500,000 lbs or more of proppant in a single stage, are often contained to propped fracture heights of less than 50 ft. Few vertical unconventional wells are currently drilled now that most economic Marcellus fairways are well into their development phase. Vertical wells and their learnings are often forgotten with the many personnel and role changes, acquisitions, mergers and other fast paced changes in the industry over the last decade. The purpose of this paper is to reintroduce the valuable and still relevant vital information from these forgotten vertical wells.
Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.
Abstract Polyacrylamide-based friction reducers (FRs) are widely used in hydraulic fracturing to reduce friction created within fluid as it flows through tubulars or other restrictions. These polymers generally add viscosity to the fluid to reduce the turbulence induced as fluid flows. Type and amount of total dissolved solids (TDS) in source water have significant impact on performance of FRs. This study investigates these effects and evaluates various types of FRs applied to the Marcellus Shale region. It was found that increase in salinity often causes significant performance degradation (Mantell et al., 2011). This is especially critical for application of FRs in Marcellus shale that is known for challenging brine contents. This effect is more pronounced for some divalent cations than for monovalent ones. Addition of surfactant systems can improve FR performance by extending the salt tolerance. Overall, it can be concluded that FR optimization for given water content and proppant can be done by adjusting FR type and/or concentration. For special applications, when higher proppant loading is desired, applying Viscosifying Friction Reducers (VFRs) and High Viscosity Friction Reducers (HVFRs) are proven to be preferable. It was demonstrated that slickwater viscosity tend to increase exponentially with VFR concentration increase. At the same time VFRs should be breakable to ensure high regained proppant conductivity and minimization of formation damage. Such result would further justify the transition from traditional gelled fluids to FR-based viscous slickwater. This comprehensive review explores the application of various types of FRs for Marcellus shale region. It defines the critical TDS levels, and types of cations that require changes in FR type or dosage. This data can benefit operators in (1) optimizing performance of the FR-based completion fluid; (2) avoiding formation damage associated with usage of unjustified additives; and (3) comparing/qualifying FRs based on their optimal range of application and economical dosage.
The direction of unconventional developments has been a roller-coaster ride, not only in the realms of financing and profitability, but very much in the technical execution of the well construction and the completion phases, too. This is particularly the case for those aspects relating to the completion and hydraulic fracturing operations. There are few parties, I believe, that would disagree that the drilling community rapidly delivered an extremely coherent and efficient learning curve, something that the completion/fracturing discipline has unfortunately been much slower to achieve. This is not in the least surprising. Effectively extending conventional technologies and focusing on key requirements (i.e., getting from point A to point B) worked well for drilling teams.
In the past decades, the success of unconventional hydrocarbon resource development can be attributed primarily to the improved understanding of fracture systems, including both hydraulically induced fractures and natural fracture networks. To tackle the fracture characterization problem, several recent papers have provided novel insights into fracture modeling technique. Because of the complex nature and heterogeneity of rock discontinuity, fabric, and texture, the fracture-modeling process typically suffers from limited data availability. Research shows that modeling results reached without interrogation of high-resolution petrophysical and geomechanical data can mislead because the fluid flow is actually controlled by fine-scale rock properties. A more-reliable fracture geometry can be obtained from an enhanced modeling process that preserves the signature from high-frequency data.
The argument for making friction reducer on site is simple: only one truck is required to deliver dry polymer vs. three loads required for the same amount of liquid additive. For Downhole Chemical Solutions (DCS), reducing the number of trips and the amount of chemicals needed to create a stable liquid by mixing it as needed on site reduces the average cost of a gallon of friction reducer by around 30%, said Mark Van Domelen, vice president of technology for DCS. "The business is very cutthroat and competitive on the pricing of polyacrylamide. We can reduce the cost further on friction reducer," using dry polymer, he said. Polyacrylamide is generally described as the key component in friction reducers.
When trying to understand the well-to-well events known as frac hits and fracture-driven interactions (FDIs), the first idea to embrace is this: they are not all the same. "And the key physical mechanisms are not the same," said Mark McClure, who added that, "Until you've really dialed in on what those are, you're really in the dark." McClure is the cofounder and CEO of ResFrac Corp. In March, the modeling firm began a multiclient study to diagnose the relationships between parent and child wells--or what many consider to be the ultimate subsurface challenge facing the shale sector. Participating operators are Marathon Oil, Hess Corp., Pioneer Resources, Arc Resources, Birchcliff Energy, SM Energy, and Ovintiv Inc.