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Abstract Maximizing recoveries and understanding associated reserve uplifts through the optimal completion design are major themes across North American unconventional plays. Thus, recognizing where the Montney sits in context to other plays in Western Canada is an integral component in evaluating the competitive landscape for investors and operators. This analysis compares completion trends across North America to highlight the impact of different completion designs on well performance. Additionally, the effect of completion designs on parent-child communication is analyzed. An overview of the industry regarding proppant intensity (lbs/ft) and the lateral length is presented, followed by an in-depth statistical analysis on the Montney and Deep Basin plays in the Western Canadian Sedimentary Basin (WSCB). The parent-child well analysis highlights how operators in the Montney Formation can maximize resource recovery while mitigating well failure. The study finds proppant intensity is the driving force behind the rate of change in the industry. However, larger completions can increase associated risk with offsetting well failures as plays move further into development mode. Our results suggest operators can maximize resource recovery through increased completion intensities and minimize parent well failure by moving toward pad completions. Introduction The Montney Formation, a Triassic siltstone that contains multiple stacked zones, is one of the most actively drilled plays in Canada. With the upstream oil and gas industry becoming increasingly competitive, it is imperative to understand where the Montney sits among its peers. Analyzing trends across North America, proppant intensity levels increased in recent years in many of the key resource plays in the U.S. However, operators in Canada tend to be more conservative and have yet to adopt similar completion designs. This study analyzes completion trends across North America and focuses on parameters such as proppant intensity and lateral length. A statistical evaluation of completions in the Montney and Deep Basin plays shows the effect of each parameter on EURs, and the parent-child analysis on the Montney Formation examines the risk associated with frac'ing offsetting child wells.
Abstract The science of hydraulic fracturing (HF) has long understood the impact of fracture conductivity on well success. As HF was applied to unconventional reservoir development, increasing contact area was deemed a first-order priority. While conductivity still remained important, the downturn in the industry led many operators to replace premium (high conductivity) designs with large volume designs employing low quality (conductivity) proppant. These high contact area designs have now seen 2-3 years of production results that can now be analyzed and compared to higher conductivity designs. This paper will review the physics of finding the optimal balance between reservoir contact and fracture conductivity in the context of unconventional reservoir development. The authors will model an actual Haynesville completion/fracture design by performing frac pressure-matching and then history-match to actual production through the use of a numeric reservoir simulator. In addition, actual field production will be compared in several unconventional basins to support the results found in the history-matched models. These basins include North Louisiana (Haynesville), Williston (Middle Bakken) and South Texas (Eagle Ford). In addition economics will be applied to the production comparisons to identify the completion designs which provide the highest return on investment. Introduction Since its inception in the 1940s, hydraulic fracturing has been used to enhance productivity and increase recovery in oil and gas wells. Most applications of this technology prior to the 2000's were in conventional reservoirs, including high perm oil as well as tight gas fields exploited with vertical wellbores. During this time the science behind hydraulic fracturing rapidly advanced from using novel techniques [Howard 1970] to more advanced fluids, proppant and pre/post job analysis incorporating various fracture diagnostic methods [Gidley 1989]. With a few notable exceptions [Mayerhofer 1997], the industry has recognized the necessity of proppant for the success of these treatments [Montgomery 1985]. As engineers began to understand proppant performance at downhole conditions, proppant selection evolved from a simple "depth and stress" question, to a more complicated process which employed fracture models and well productivity predictions [Barree 2003, Palisch 2007] to determine the proppant and fracture design which maximized the EUR and return on investment of assets. The industry soon found that hydraulic fractures were "conductivity limited", meaning that increasing fracture conductivity yielded increased production in most applications worldwide [Vincent 2002]. The only question was how to economically increase fracture conductivity such that well economics were positively impacted. As the industry began developing unconventional resources, hydraulic fracturing became even more critical, and given the ultra-low permeability rock, some began to question whether fracture conductivity was still important. While much debate ensued, numerous case histories and field studies were published which confirmed the importance and potential benefit of higher conductivity fracture treatments in these ultra-low permeability, multi-stage treatments in horizontal wells [Blackwood 2011, Jackson 2014, Vincent 2011].
Deriving meaningful insight from mass amounts of data, oftentimes acquired through various sources and delivered in different formats, has proven to be a difficult feat for many E&P operators. With the constant push for efficiency gains in both job design and execution, data-driven decisions have become essential for sustaining activity at a peak level. Most data analytics models evaluate data on a statistical basis, but there is a lack of expertise to truly understand, clean, and filter public data ingested into their models. Additionally, these models do not quantify the impacts of important completion and reservoir parameters on production. In certain formations, E&P operators may have better data for their acreage, but do not have complete knowledge of the entire basin, causing them to overlook key completion optimization techniques. Drawing from both internal data and public data provides the quantity and diverse data set needed to create a robust model.
This paper presents a cloud-based completions optimization platform, providing a toolbox with models built for specific basins to identify, rank, and optimize key completion drivers for a selection of wells. Optimized parameters include proppant and fluid intensity, perforation intervals, fracturing fluid types, and proppant loadings and types. The user examines parameters individually to quantify the impact and establish appropriate parameter values. The web-based application shows a model-generated heat map of production potential for a given area. The model predicts production based on real-time changes made to completion parameters. For example, changing the location of the well or increasing the proppant intensity per foot to an optimal amount will give a corresponding predicted production relative to all executed fracturing designs. Users also leverage the economic model and input individual variable costs to get an overall completion cost per 12-month BOE or corresponding NPV.
Validating the model with an operator’s completion and production data in the Permian helps to provide the feedback needed to further development. The production potential heat map shows where prime acreage resides and quantifies expected production for a selected area based on comparable peers that are producing from the same geological land quality. Proppant and fluid intensity, volumes, and types along with other completion parameters are ranked, examined, and optimized. Using the online completions optimization tool to design and execute a design in fracturing operations would further validate the model’s effectiveness and its ability to be integrated into completion design workflows.
There are numerous traditional modeling and simulation methods currently used to optimize various completion parameters, which take anywhere from weeks to months to perform. The cloud-based platform not only combines private and public data, but its models have also been validated with production data to show it has an accurate basis for its predictions. Knowing the reservoir potential upfront helps the E&P operator to plan their drilling and completions program. As opposed to executing a standard template design in a given area, it enables E&P operators to properly customize the completion and fluid design for every well based on the most important completion drivers.
Abstract In the absence of significant formation-stress contrasts between adjacentzones, the frac-fluid density will determine the preferred growth direction of a vertical hydraulic fracture. A vertical hydraulic fracture will grow in aradial or penny-shaped manner if the frac-fluid density is approximately equal to the gradient of the least principal formation stress. Upward growth is favored if the formation-stress gradient exceeds the frac-fluid density. Even in the presence of significant stress barriers, frac-fluid density may influence the fracture-growth direction within the pay zone and after the hydraulic fracture has penetrated into the barrier layers. This paper presents a closed-form solution to rapidly assess the effect of treatment fluid density and proppant loading on hydraulic fracture growth direction and width under a given formation-stress state. This solution was used to: Explain the apparent lack of downward growth in specific hydraulic fracture stimulation treatments Confirm that large treatment intervals can be successfully stimulated with one treatment Determine where a horizontal well should be located within the pay zone to maximize coverage by subsequent fracture treatments These solutions have been successfully used to answer questions such as: P. 91
Abstract Recent wells from the Haynesville Shale show materially higher productivity and expected recoveries compared to older vintages. The improvements, visible on absolute and lateral-normalized bases, occurred in both the historical core of the play and previously uneconomic areas, with well costs decreasing even as completion designs intensified. This study analyzed geologic, completion, and production data across the Haynesville play in a multivariate analysis to characterize and identify the key drivers making this play successful and expanding its economic limits. Introduction The Haynesville Shale of East Texas and North Louisiana was viewed as one of the most prolific shale-gas resources when it first emerged in late 2008. Production quickly increased into 2011 as it became the largest- producing gas play in the Lower 48, a reflection of highly productive wells and favorable commodity prices. The crash of natural gas prices in 2012, a surge of Appalachian gas production and the Haynesville's steep declines and high well costs shifted activity and interest away from the play. In 2015, despite weak commodity prices, rig activity rebounded as operators began to drill more completion-intensive wells with considerable well cost reductions. Recent results show significant improvements in both the historical core of the play and previously uneconomic areas. This study analyzed geologic, production and completion data to characterize the Haynesville play to identify key drivers making this play successful. The Upper Jurassic Haynesville Shale is an organic- and carbonate-rich mudrock deposited in a restricted basin, with paleo structures and topography strongly influencing lithology trends across the play (Steinhoff et al, 2011; Hammes et al, 2011). The Haynesville reservoir ranges from 100– to 300-feet thick and is characterized by overpressuring (pressure gradients of 0.8 to 0.9 psi/ft), 8% to 15% porosity and depths of 11,000 to 14,000 feet. The play currently produces about 5 Bcf/d of dry gas, with initial peak calendar-day rates from recent wells averaging 15 MMcf/d. These new wells are forecast to recover about 10.5 Bcf over 30-year producing lives.