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Abstract In some basins, large scale development of unconventional stacked-target plays requires early election of well targeting and spacing. Changes to the initial well construction framework can take years to implement due to lead times for land, permitting, and corporate planning. Over time, as operators wish to fine tune their development plans, completion design flexibility represents a powerful force for optimization. Hydraulic fracturing treatment plans may be adjusted and customized close to the time of investment. With a practical approach that takes advantage of physics-based modeling and data analysis, we demonstrate how to create a high-confidence, integrated well spacing and completion design strategy for both frontier and mature field development. The Dynamic Stimulated Reservoir Volume (DSRV) workflow forms the backbone of the physics-based approach, constraining simulations against treatment, flow-back, production, and pressure-buildup (PBU) data. Depending on the amount of input data available and mechanisms investigated, one can invoke various levels of rigor in coupling geomechanics and fluid flow – ranging from proxies to full iterative coupling. To answer spacing and completions questions in the Denver Basin, also known as the Denver-Julesburg (DJ) Basin, we extend this modeling workflow to multi-well, multi-target, and multi-variate space. With proper calibration, we are able generate production performance predictions across the field for a range of subsurface, well spacing, and completion scenarios. Results allow us to co-optimize well spacing and completion size for this multi-layer column. Insights about the impacts of geology and reservoir conditions highlight the potential for design customization across the play. Results are further validated against actual data using an elegant multi-well surveillance technique that better illuminates design space. Several elements of subsurface characterization potentially impact the interactions among design variables. In particular, reservoir fluid property variations create important effects during injection and production. Also, both data analysis and modeling support a key relationship involving well spacing and the efficient creation of stimulated reservoir volumes. This relationship provides a lever that can be utilized to improve value based on corporate needs and commodity price. We introduce these observations to be further tested in the field and models.
Abstract Accelerating the learning curve in the development of the Vaca Muerta utilizing lessons learned in North American unconventional resource plays is the focus of this paper. Reducing completion costs while maintaining high productivity has become a key objective in the current low-price environment. Completion diagnostics have been demonstrated to optimize stimulation and completion parameters that have shaped successful field developments. The paper reviews stimulation diagnostic data from wells completed in the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara shale formations. Case histories are presented in which proppant and fluid tracers were successfully employed in completion optimization processes. In the examples presented, diagnostic results were used to assess the stimulation of high productivity intervals within a target zone, evaluate various completion methods, and optimize stage and cluster spacing. The diagnostic data were compared with post-frac production rates in an effort to correlate completion changes with well performance. Results presented compare first, engineered perforations versus conventional geometrically spaced perforations to drive up effectiveness in cluster stimulation. Second, new chemistries, such as nanosurfactant, versus conventional chemistries to cut either completion cost or prove their profitability. Third, employing an effective choke management strategy to improve well productivity. Last, as in any stacked pay, determining fracture height growth in order to optimize well density, well spacing, field development and ultimately the recovery of the natural resources. Completion effectiveness is shown to be improved by landing laterals in high productivity target intervals, increasing proppant coverage across the lateral by utilizing the most effective completion methods, optimizing cluster spacing and decreasing the number of stages to reduce completion costs while achieving comparable production rates. Cluster treatment efficiency (CTE), in particular, has become a critical metric when optimizing hydraulic fracturing treatment designs based on current and future well densities. It can be used to rationalize well performance as well as to identify possible candidates for a refrac program. Using completion diagnostics, successful completion techniques were identified that led to production enhancements and cost reductions in prolific plays such as the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara.
ABSTRACT: Heterogeneity of an unconventional reservoir is one of the main factors affecting production. Well performance depends on the size and efficiency of the interconnected fracture “plumbing system”, as influenced by multistage hydraulic fracturing. A complex, interconnected natural fracture network can significantly increase the size of stimulated reservoir volume, provide additional surface area contact and enhance permeability. The purpose of this study was to characterize the natural fracture patterns occurring in the unconventional Niobrara reservoir and to determine the drivers that influenced fracture trends and distributions. Highly fractured areas/fracture swarm corridors were identified and integrated into a reservoir model though DFN (Discrete Fracture Network) application for further prediction of reservoir performance using reservoir simulations. The predictive capability of DFN models can aid in improved reservoir performance and hydrocarbon production through optimized well spacing, re-frac stage locations planning for existing wells as well as completion strategies design for new wells.
The Codell formation is a low permeability, clay rich, late Cretaceous agesandstone within the Wattenberg field of the DJ Basin. Since 1997 over 1500Codell wells have been restimulated. Results on the past 200 refractured Codellwells using a reduced CMG polymer fluid system have yielded incremental monthlyproduction results in excess of 1900 BOE/well or approximately 80% of theoriginal initial production. Success of this program is believed to be thecombination of stringent well selection criteria, high fluid quality controlguidelines and effective operational field practices. It is believed that dueto this recent success in restimulating the Codell, over 4000 additional wellswithin the DJ Basin may be restimulated with economic benefits.
This paper will discuss completion history of the Codell formation and howcriteria from candidate selection to fluid quality may impact the success ofsuch a program.
Records indicate that the first Codell completion in the Wattenberg field ofthe Denver-Julesburg basin occurred in 1955. It was not until the early 1980'sthat the Codell became a major gas play. Since that time thousands of Codellwells have been developed within an area of approximately 100,000,000acres.1 The DJ basin shown in Figure 1 is an asymmetricalbasin just north of Denver, Colorado with the axis of the basin runningparallel to the Front Range uplift.
The Codell, described as Type 2 sandstone by Weimer andSonnenberg2, is a member of the Upper Cretaceous Carlile shale. Itis a bioturbated, reworked fine-grained marine shelf sandstone without acentral bar facies and is laterally continuous across the field area. Figure2 is a stratigraphic sequence of formations bounding the Codell within theDJ Basin. Over the years, many wells have included the Niobrara formation bymeans of separate completions on both the Niobrara and Codell or simultaneouslystimulating both formations with limited entry techniques.3Production from the Niobrara often times has proved to be limited due tonanodarcy matrix permeability. Due to the Niobrara inconsistency, a greatnumber of wells were completed solely in the Codell interval.
These reservoirs were initially over pressured with a pore pressure gradientof ±0.60 psi/ft.4 Pay thickness in the Codell can range from 14 to20 ft. within the central portion of the basin at typical depths of 7000 - 7200feet. Bottom hole temperatures are generally between 230-250° F BHST. It is aclay rich sandstone (15-25% by volume) with pore filling and pore lining mixedlayer illite/smecite clays. Permeability is low (i.e., <0.1 millidarcies),with Density log measured porosity ranging from 8 to 20%.
Aggressive exploration and development of the Codell led to severalexperimental completion techniques throughout the years. Wells were stimulatedwithout regard to geological and lithologic variations. A wide range of fluidtypes and treatment designs were implemented in order to achieve an economicalrate of return.
Original Codell Completions
An obvious contributor to the potential for restimulations is the originalcompletion. The Codell formation has a history that begins in the middle 1950'sand continues today with the continued drilling of acreage within the DJ Basin.Original completion techniques and stimulation fluids utilized have affectedthe results of restimulation programs.