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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Clemens, Carter (BP) | Rivas, Bruno S. (Mexico National Hydrocarbons Commission) | Atkinson, Angela Dang (Encana Corp.) | Mohan, Jesma (Schlumberger) | Garg, Lavish (Weatherford) | Pradhan, Yogashri (Endeavor Energy Resources) | Ighalo, Samuel (Halliburton) | Nunoo, Nii Ahele (NOV) | Mandzhieva, Radmila (Independent) | Lal, Tarang (Aera Energy)
Special Section: The Value and Future of Petroleum Engineering
JPT asked several active young professionals about their career path thus far and what they liked about petroleum engineering. Here are some of their answers.
Carter Clemens, BP
I lucked into the petroleum industry; I did not know much about it before choosing it as a major at the University of Texas. It has allowed me to live and travel to distant countries I never thought I would visit—whether it is Abu Dhabi, Port of Spain, Cairo, or Aberdeen, the oil industry has an incredible reach to some interesting locations. It has also enabled me to pursue engineering while spending a lot of my time outside instead of in front of a computer screen. When I was riding around with well operators in Wyoming and Colorado, I thought of how lucky I was to not be in a cubicle. There is something special about being on a well-site surrounded by snow in Wyoming or watching a sunrise from a rig in the middle of the ocean—you can’t get that with most industries.
Bruno S. Rivas, Mexico National Hydrocarbons Commission
Petroleum engineering is more than get-ting oil out of the ground; it means delivering the energy that the world needs to fight poverty, increase human wellness, and accelerate growth in a sustainable way. The oil and gas industry has given me the opportunity to interact with professionals from all over the world, to exchange different experiences, to solve problems in a responsible and efficient manner, and to inspire future generations. With no doubt, if I had to decide again what to study, my choice would be oil and gas; it is certainly not an easy path, but realizing that I’m generating a positive impact on others’ lives is a personal satisfaction.
Let’s Talk Climate Change
Angela Dang Atkinson, Encana Corp.
I love saying, “I’m a petroleum engineer and I believe in anthropogenic climate change.” It catches people off guard and begins a nuanced conversation about energy. It is an opportunity for me to talk about the importance of incremental change and that there is no silver bullet in solving the world’s energy challenges. As Harvard economics professor Ed Glaeser states, “Once we start thinking that there’s a silver bullet…we lose the fact that we need to be working day by day, over decades, to effect change.” We, the oil industry, are among those working day by day to effect change—whether we are increasing the use of recycled fracture water or finding creative ways to reduce emissions, these are the types of incremental gains on the way to better energy solutions. This nuanced conversation should not primarily exist in 150-character tidbits online. It is up to us to have that conversation in a grassroots manner, face to face, with our community.
Abstract In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or "frac hits". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention. Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data. In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (Daneshy, 2018), and fracture-to-fracture connections both temporary and long term. As fracture operations approached a primary vertical well (depleted zones), frac fluid was distributed vertically among multiple horizons through perforations in the existing well and laterally into horizontal primary wells. The three laterally closest primary wells, completed in three different intervals, had similar strong pressure responses to a common active stage suggesting a geologic cause. As for the vertical observation wells, fluid incursion was observed over 8400 feet away. The vertical wells between the two horizontal active infills had a 200 ft. to 400 ft. radius of pressure disturbance as the frac stages approached their locations. Fracture stages within the 200 ft. to 400 ft. radius caused direct hits while stages outside this radius caused mild pressure increases identified as fracture shadows. Legacy fields in Midland Basin are usually Held by Production (HBP). Consequently, horizontal development may be around existing vertical wells. Redevelopment of acreage into unexploited benches after primary benches have been horizontally developed is another situation many companies face. By sharing this case study, the authors want other operators who are facing these common issues to leverage these learnings. The significance of ignoring potential fracture interference and hydraulic connection may result in ineffective fractures, reduced stimulated reservoir volume (SRV), or wells sharing SRV. Ultimately this means reduced resource recovery which may occur in either or both the primary and infill wells.
Maeso, Carlos Jeronimo (Schlumberger) | Ponziani, Michel (Delft University of Technology) | Le Nir, Isabelle (Schlumberger) | Kherroubi, Josselin (Schlumberger) | Quesada, Daniel (Schlumberger) | Dubourg, Isabelle (Schlumberger) | Luthi, Stefan M. (Delft University of Technology) | Slob, Evert C. (Delft University of Technology) | Fisher, Kelvin (Endeavor Energy Resources) | Honeyman, Les (Endeavor Energy Resources) | Brown, Randy (Endeavor Energy Resources) | Zenned, Olfa (Schlumberger)
The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time.
Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors’ geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined.
Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.