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Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
Abstract The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations. Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions. Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
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 Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
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.
Summary The Codell Sandstone has recently been the subject of extensive exploration and subsequent development activity in both the Colorado and Wyoming portions of northern DJ Basin. The Niobrara Formation has been the primary historical exploration target since the late 1980's due to success at the Silo Field from horizontal wells drilled in the Niobrara B Bench. In 2009, EOG Resources discovered the Hereford Field with the Jake 02-01H, producing approximately 1700 barrels of oil per day initially from the Niobrara B Bench. The next two years in the area saw much drilling focused for the Niobrara B Bench with the completion of many non-commercial wells. In 2012, SM Energy drilled a lateral focused on evaluating the Codell Sandstone. Cirque Resources, Kaiser Francis and EOG soon followed with their own exploratory wells, establishing the play. This new play area is thermally in the oil window. Codell Sandstone oil producers have gas-oil ratios less than 2000 scf/bbl. The Codell Sandstone thins from north to south due to erosional truncation beneath an angular unconformity at the base of the Fort Hays Limestone Member of the Niobrara Formation. Gross thickness ranges from 18 to 33 feet. The Codell Sandstone is a very-fine to fine-grained sandstone and produces oil from two main facies: bioturbated sandstone and laminated sandstone. The laminated facies is parallel to sub-horizontally bedded, has 8 to 15 percent porosity, and .01 to 0.10 millidarcies permeability. The bioturbated sandstone has 8 to 13 percent porosity and .008 to .05 millidarcies permeability. The Codell Sandstone is a low-resistivity pay zone that produces oil with low water cuts from zones with less than 10 ohm-m resistivity. Clay content is 15–25% with abundant microporosity as imaged with epifluorescent microscopy, accounting for high bound water content and explaining the low formation resistivity. Oil typing indicates the oil found in the Codell is sourced from the Niobrara and is distributed across the area through migration. Oil saturation varies across the play depending the on the distance from areas of oil generation and expulsion into the Codell. Use of mercury capillary injection pressure analysis was essential in resolving the oil migration route throughout the play area. Drilling and completion techniques have evolved since the first wells were drilled. Best practices to date involve 1280 acre spacing units with 9300' lateral lengths, cemented liner with perf & plug completion techniques. Introduction The DJ Basin has been a very active province for exploration and development in the recent horizontal drilling boom since 2009. Driven primarily by the Niobrara Formation, the Codell Sandstone has also been a large contributor to activity. Due to all of this activity, both within the core of the Wattenberg Field as well as the step out activity in both Colorado and Wyoming, the production for the basin has increased from 192,000 BOEPD in 2010 to over 480,000 BOEPD in early 2016.
Summary Horizontal drilling and artificial stimulation have made the Cretaceous Niobrara Formation, Denver-Julesburg Basin, a prolific, self-sourced, unconventional reservoir that yields both gas and liquids. As a carbonate-dominated reservoir, pore networks documented in most other unconventional shale reservoirs are not necessarily analogous. In this study pore system characterization was achieved using focused ion-beam scanning electron microscopy (FIB-SEM) and Avizo Fire™ image segmenting software. We focused on samples from the B chalk, which is the primary landing zone for horizontal wells in the Niobrara. Material was examined from four cores representing thermal maturities ranging from the oil window (Ro≈0.7, GOR ≈ 1,000) to the dry-gas window (Ro≈1.2, GOR >20,000). At the microfacies scale, samples consisted of chalks, marly chalks, chalky marls, and submillimeter laminations of marl in the chalk. Electron microprobe elemental mapping shows that organic macerals are concentrated in the marl interlaminations whereas finely disseminated organic matter is in peloids (particularly those that are black in thin section). Intercrystalline pores dominate all samples and occur primarily between fragments of coccolith debris and recrystallized calcite, and to a lesser degree between clay minerals. Median equivalent circular diameters of intercrystalline pores range from ~100 to 400 nm. Total image porosity averages 3.9% with a range of 1.4% to 10%. Highest porosity is in peloids within marly chalks. Residual hydrocarbon fills many former intercrystalline pores and organic macerals occur in marl lamina. In most cases, residual hydrocarbon-filled pores exceed the amount of open pores, and those filled pores have median equivalent diameters than range from 300 to 900 nm. Organic material exhibits intraparticle "bubble" pores with the abundance of bubble porosity in organics showing no increase with thermal maturity above ~0.7 Ro. The size of hydrocarbon-filled pores is greatest in the most thermally mature well, and greater than the size of open intercrystalline pores in all wells. This suggests pores that were not filled by organic matter underwent continued reduction due to diagenesis after hydrocarbon migration.
Abstract Maximizing well productivity and improving drilling efficiency remains a major challenge while drilling horizontal wells in US-land unconventional shale plays in the last few years. Reducing drilling times and eliminating trips for the curve bottomhole assembly (BHA) requires a motor that can be rotated at high RPM in the vertical section while still achieving buildup rate (BUR) in the curve. The challenges of horizontal well drilling in US land led to the recent introduction of a steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. These ODMs achieved higher BUR in the curves than the conventional motors at lower adjustable kick-off (AKO) sub angle. Although the planned dogleg severities (DLS) stayed at the similar level, drilling vertical and curve sections of the horizontal wells in the Niobrara shale unconventional play posed additional challenges: –Rotating the BHA in the vertical section with a high AKO angle –Dealing with formation challenges –Holding the toolface to achieve consistent BUR in the curve –Completing the vertical and curve sections in one run The introduction in 2013 of the latest-generation steerable motors (LGSM) with further reduced short BTB distance design helped the operator overcome these challenges. The new system significantly improved drilling performance with excellent directional control. This paper will discuss the design, testing and results of horizontal wells drilled using the LGSM in the Niobrara unconventional shale play.
Introduction The seismic characterization of the Niobrara presented here is based on recently acquired wide-azimuth 3D seismic data in Weld County, N.E Colorado (Figure 1), and publically available well data for calibration within the area. The presentation starts with the location and geologic setting of the Niobrara and its vertical reference to the seismic response (Figure 2). An association is made using geometric attributes relating the complex subtle faulting to the Laramide Orogeny, which occurred in a series of pulses with intervening quiescent phases, possibly influencing hydrocarbon production. This sets the local structural framework for using fracture anisotropy and related rock properties for locating possible areas of significant interest. The Niobrara Formation lies in a thermally mature fairway which today is the Denver-Julesburg Basin. These sediments were deposited in an ancient Cretaceous seaway (Western Interior Seaway) running in a north-south direction through the mid-western United States, with ends open to the ocean. The Niobrara is carbonate rich on the east side, where the study area is located producing oil, and clay rich on the west side of the Basin. The Smoky Hill Chalk Member is 300–400 ft thick and composed of three key limestones (chalk) benches A, B and C which are each approximately 30–40 ft. thick (Figure 2). They are named from their resistive nature as seen along cliff exposures, and are intercalated with organic rich marls, the source rock. URTeC 1576924
The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.” That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis. Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage. There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US. Reservoir Rock and Producing Regions Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”
Summary Active development of the Upper Cretaceous Niobrara and Codell reservoirs in the Denver-Julesburg basin has resulted in about 2,000 completions since 1981. A detailed evaluation of the producing characteristics and economics of wells in this 800,000-acre [323 760-ha] play show that high-GOR wells and wells in the top one-third percentile play show that high-GOR wells and wells in the top one-third percentile will yield a positive discounted net cash flow with today's costs and prices. Reservoir heterogeneity and varying completion techniques used to prices. Reservoir heterogeneity and varying completion techniques used to date will make it difficult to predict with a high degree of certainty the location of future top one-third wells. Ultimate reserves for an average Codell or Codell/Niobrara well are estimated to be 13,000 STB [2067 stock-tank m3] oil and 110 MMscf [3.1 × 10(6) std m3] gas. With drilling and completion costs of $185,000, oil and gas prices will have to rise some 40% above current levels to yield acceptable rates of return. A sensitivity analysis is presented to show how changes in well costs, production profiles, and the other variables will affect net present value production profiles, and the other variables will affect net present value (NPV). Introduction The Upper Cretaceous Codell sandstone and Niobrara limestone is the source of a major oil and gas play in the west central portion of the Denver-Julesburg basin. The play is developing in an 800,000-acre [323 760-ha] area north of Denver, CO. Even though the first discovery of producible hydrocarbons in the Codell was made in 1955, few wells in the study area were completed in the Codell and Niobrara before 1981. About 1,900 wells were completed between 1981 and Dec. 1987 in the Codell, either singly or multiply with other formations. Development on 40-acre [16-ha] spacing over the entire 800,000 acres [323 760 ha] could result in 20,000 wells being drilled or recompleted into the Codell. Publicly available production and completion data from both Dwight's Energy Data Inc. and Petroleum Information Corp. were used to develop typical production profiles for Codell and Codell/Niobrara wells. These production profiles are characterized by very rapid initial declines followed by a gradual flattening. which is typical of low-permeability formations. Cumulative GOR and productivity maps were developed to delineate better-than-average productivity maps were developed to delineate better-than-average producing areas. producing areas. Economic analyses with both constant and escalated prices and costs are presented for five different production profiles. Sensitivities of NPV to oil and gas prices, drilling and completion costs, operating and maintenance costs, and various production profiles are analyzed and presented in a spider diagram. Description of Play Fig. 1 is a stratigraphic nomenclature chart of the Denver-Julesburg basin. The objectives of the current play are the Niobrara formation and the Codell sandstone member of the Carlile shale. Within the play area, the Terry and Hygiene sand above the Niobrara and the J sandstone member of the Dakota group, which is about 500 ft [152 m] below the base of the Codell, are productive in the Spindle and Wattenberg fields, respectively. The Denver-Julesburg basin, which is shown in Fig. 2 along with a portion of the Powder River and Anadarko basins, is asymmetrical, with a gently dipping eastern limb and a steeply dipping western limb. The axis of the basin runs parallel to the Front Range along a line from Cheyenne, WY, through Denver. The play is located within the Type 2 Codell sandstone as mapped and described by Weimer and Sonnenberg. The area of study for this paper is Townships 8 South to 8 North, Ranges 58 West to 70 West.