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ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
Frantz, J. H. (Deep Well Services, Matador Resources Company, Completion Team) | Tourigny, M. L. (Deep Well Services, Matador Resources Company, Completion Team) | Griffith, J. M. (Deep Well Services, Matador Resources Company, Completion Team)
Abstract In conjunction with the industry and basin-wide paradigm shift to drilling and completing extended laterals, Matador Resources Company (the operator) made significant plans in 2018 that would focus activity toward wells with laterals greater than one-mile. One operational hurdle to overcome in this shift change was the effective execution of removing frac plugs and sand at increased depths during a post-stimulation frac plug millout. Utilization of coiled-tubing units (CTUs) had been proven to be a successful millout method in one-mile laterals, but not without risk. Rig-assisted snubbing units coupled with workover rigs (WORs) provided for less risk with higher pulling strength capabilities and the ability to rotate tubing, but would often require operational time of up to twice that of typical coiled-tubing unit millouts. The stand-alone, rigless Hydraulic Completion Unit (HCU) was ultimately tested as a solution and proved to alleviate risks in extended lateral millouts while providing operational time and cost comparable to coiled-tubing units. The operator has since performed post-stimulation frac plug millouts on ~45 horizontal wells in the Delaware Basin using HCUs. The majority of these wells carried lateral lengths of over 1.5 miles. Results and benefits observed by the operator include but are not limited to the list below: 1.) Ability to safely and consistently reach total depth (TD) on extended laterals through increased snubbing/pickup force and the HCU's pipe rotating ability 2.) Ability to pump at higher circulation rates in high-pressured wells (>3,500 psi wellhead pressure) to assist in effective wellbore cleaning 3.) Smaller footprint which allows for the utilization of two units simultaneously on multi-well pads 4.) Time and cost comparable to a standard coiled-tubing millout, particularly on multi-well pads.
Guo, Yifei (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Patterson, Ross (Hess Corporation) | Zheng, Dandan (Hess Corporation) | Isbell, Matthew (Hess Corporation) | Riopelle, Austin (Marathon Oil Corporation)
Abstract Well interference, which is commonly referred to as frac hits, has become a significant factor affecting production in fractured horizontal shale wells with the increase in infill drilling in recent years. Today, there is still no clear understanding on how frac hits affect production. This paper aims to develop a process to automatically identify the different types of frac hits and to determine the effect of stage-to-well distance and frac hit intensity on long-term parent well production. First, child well completions data and parent well pressure data are processed by a frac hit detection algorithm to automatically identify different frac hit intensities and duration within each stage. This algorithm classifies frac hits based on the magnitude of the differential pressure spikes. The frac stage to parent well distance is also calculated. Then, we compare the daily production trend before and after the frac hits to determine the severity of its influence on production. Finally, any evident correlations between the stage-to-well distance, frac hit intensity and production change are identified and investigated. This work utilizes 3 datasets covering 22 horizontal wells in the Bakken Formation and 37 horizontal wells in the Eagle Ford Shale Formation. These sets included well trajectories, child well completions data, parent well pressure data and parent well production data. The frac hit detection algorithm developed can accurately detect frac hits in the available dataset with minimal false alerts. The data analysis results show that frac hit severity (production response) and intensity (pressure response) are not only affected by the distance between parent and child wells, but also affected by the directionality of the wells. Parent wells tend to experience more frac hits from the child frac stages with smaller direction angles and shorter stage-to-parent distances. Formation stress change with time is another factor that affects frac hit intensity. Depleted wells are more susceptible to frac hits even if they are further from the child wells. Also, we observe frac hits in parent wells due to a stimulation of a child well in a different shale formation. This paper presents a novel automated frac hit detection algorithm to quickly identify different types of frac hits. This paper also presents a novel way of carrying out production analysis to determine whether frac hits in a well have positive or negative influence long-term production. Additionally, the paper introduces the concept of the stage-to-well distance as a more accurate metric for analyzing the influence of frac hits on production.
Abstract A unique well-tracing design for three horizontally drilled wells is presented utilizing proppant tracers and water- and hydrocarbon-soluble tracers to evaluate multiple completion strategies. Results are combined to present an interpretation of them in the reservoir as a whole, where applicable, as well as on an individual well basis. The new approach consists of tracing the horizontal well(s) leaving unchanged segments along the wellbore to obtain relevant control group results not available otherwise. The application of the tracers throughout each wellbore was designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, intra- and inter-well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. Completion strategies are provided, and all the evaluation methodologies are described in detail to permit readers to replicate the approach. One field case study with five horizontal wells is presented. Three infill wells were drilled between two primary wells of varying ages. All wells are shale oil wells with approximately 7,700 ft lateral sections. The recovery of each tracer is compared between the surfactant treated and untreated segments on each well and totalized to see how the petroleum reservoir system is performing. A complete project economic analysis was performed to determine the viability of a chemical additive (a production enhancement surfactant). Meticulous analysis and interpretation of the proppant image logs were performed to discern the cluster stimulation efficiency during the hydraulic fracturing treatments. Furthermore, comparisons of the cluster stimulation efficiency between the two mesh sizes of proppant pumped are also provided for each of the three new unconventional well completions. The most significant new findings are the surfactant effects on the wells’ production performance, and the impact the engineered perforations with tapered shots along the stages had on the stimulation efficiency. Both the right chemistry for the formation and higher cluster stimulation efficiencies are important because they can lead to increased well oil production. The novelty of this tracing design methodology rests in the ability to generate results with a statistically relevant sample size, therefore, increasing the confidence in the conclusions and course of action in future well completions.
Abstract One of the latest developments in permanent fiber optics is ability to install and complete a well in rapidly based on the needs of the program. This paper will present the drivers leading into the operation, the data collected and the completion advances resulting from a permanent fiber conceived and executed in under four weeks. Completion changes were conceived following direct observations of distribution of flow rate, defined in a Uniformity Index. The resulting changes were cost neutral to the overall program but showed improved completion results and well performance.
Abstract Reducing well costs in unconventional development while maintaining or improving production continues to be important to the success of operators. Generally, the primary drivers for oil and gas production are treatment fluid volume, proppant mass, and the number of stages or intervals along the well. Increasing these variables typically results in increased costs, causing additional time and complexity to complete these larger designs. Simultaneously completing two wells using the same volumes, rates, and number of stages as for any previous single well, allows for more lateral length or volume completed per day. This paper presents the necessary developments and outcomes of a completion technique utilizing a single hydraulic fracturing spread to simultaneously stimulate two or more horizontal wells. The goal of this technique is to increase operational efficiency, lower completion cost, and reduce the time from permitting a well to production of that well—without negatively impacting the primary drivers of well performance. To date this technique has been successfully performed in both the Bakken and Permian basins in more than 200 wells, proving its success can translate to other unconventional fields and operations. Ultimately, over 200 wells were successfully completed simultaneously, resulting in a 45% increase in completion speed and significant decrease in completion costs, while still maintaining equivalent well performance. This type of simultaneous completion scenario continues to be implemented and improved upon to improve asset returns.
There are cost advantages to reaming while drilling. The pilot hole offers good directional control while the enlarged hole from reaming creates the right conditions for running casing or completion equipment which relates to savings in time and cost. An underreamer is device designed to run in conjunction with a drill bit. It has cutters that can be expanded or contracted by mechanical or hydraulic means and used to enlarge or ream a borehole below the casing. Baker Hughes and Statoil jointly developed the industry's first on-command digital reamer as a single size prototype in 2007.
This page provides SPE members access to the May 2021 issue -- digital, pdf, and online. Digital archive of issues back to January 2020 is available – scroll down from the current issue cover. These are the papers synopsized in JPT this month. They are available to SPE members only through 30 June 2021. There are also links to them at the bottom of each related synopsis.