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The authors used a high-quality digital-log data set to characterize reservoir quality accurately in the Niobrara and Codell Formations in the Denver-Julesberg (DJ) Basin. A petrophysical work flow was developed, and detailed mapping of the reservoir attributes was completed. The log-derived parameters, along with an aeromagnetic and vitrinite-reflectance data set, provided excellent insight into which geologic parameters could be tied best to well-production response. In 2013, the authors began to evaluate production response in an area where nearly 50 Niobrara wells were completed by a single operator with a similar completion design for all wells. There was a wide variation in production results after 180 days of production, ranging from 4 to 16 BOE/lateral ft. The amount of proppant pumped per lateral foot changed very little and ranged between 800 and approximately 1,000 lbm/ft.
Ramos, Claudio R. (Pro Technics Division of Core Laboratories LP) | Warren, Mark N. (Pro Technics Division of Core Laboratories LP) | Jayakumar, Swathika (Pro Technics Division of Core Laboratories LP)
Abstract The optimistic outlook of the petroleum E&P industry, especially with regard to the re-balancing of oil and natural gas prices, has led to a renewed interest in tight gas and liquids-rich plays, more specifically in the Niobrara and Codell formations in the Denver-Julesburg (DJ) Basin. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions. Formations with less than one millidarcy permeability require reservoir stimulation in order to economically produce oil and gas. Engineers will often optimize a well's completion, spacing and hydraulic fracturing treatments to maximize its return with respect to cost. This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Niobrara and Codell formations. In addition, case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability and, ultimately, increased production performance. A horizontal well database (> 350 wells) was compiled to identify effective completion trends across the Niobrara and Codell formations. By employing proppant and fluid-based tracers, hydraulic fracture geometry, well deliverability and production performance were measured to identify trends that increased overall completion effectiveness. Primary completion results highlight areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster/sleeveefficiency, wellbore lateral length and inter-well communication between Niobrara and Codell formations. Many of the insights gained through this use of post-stimulation completion diagnostics in the Niobrara and Codell formations have led to increased completion optimization, production enhancements and field-wide cost reductions.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180217, “The Impact of Petrophysical and Completion Parameters on Production in the Denver-Julesberg Basin,” by Fred Miller, Carrizo Oil and Gas; Jon Payne, Eureka Geological Consulting; and Howard Melcher, Jim Reagan, and Leen Weijers, Liberty Oilfield Services, prepared for the 2016 SPE Low Permeability Symposium, Denver, 5–6 May. The paper has not been peer reviewed.
The authors used a high-quality digital-log data set to characterize reservoir quality accurately in the Niobrara and Codell Formations in the Denver-Julesberg (DJ) Basin. A petrophysical work flow was developed, and detailed mapping of the reservoir attributes was completed. The log-derived parameters, along with an aeromagnetic and vitrinite-reflectance data set, provided excellent insight into which geologic parameters could be tied best to well-production response.
In 2013, the authors began to evaluate production response in an area where nearly 50 Niobrara wells were completed by a single operator with a similar completion design for all wells. There was a wide variation in production results after 180 days of production, ranging from 4 to 16 BOE/lateral ft. The amount of proppant pumped per lateral foot changed very little and ranged between 800 and approximately 1,000 lbm/ft. The dramatic change in production response in light of the absence of major completion changes led to the early conclusion that geology is of great importance in the the Niobrara and Codell.
In the early days of DJ production, horizontal-well-development operators did not generally make radical changes to completion designs, making it harder to evaluate the effect of these changes. Only since 2014 has a significant change from previous approaches been seen, with a new focus on a reduction in cost per BOE.
Starting in 2009, stage count for mostly short (approximately 4,300-ft) laterals varied between 10 and 20 stages, with average stage intensity of 300 ft/stage. One of the first horizontal wells in the basin started with five stages, after which stage count quickly jumped to 16 to 20 stages in a short lateral. In recent years, stage count has increased significantly, partly because of longer extended-reach laterals and partly because of higher stage intensity. Stage intensity has dropped below 200 ft/stage, with some operators now experimenting with 125 ft/stage.
Fluid and proppant volumes on a per-lateral-foot basis have not changed as dramatically in the DJ Basin as they have in other major US shale plays. Rate and rate per lateral foot show a similar lack of change over the first few years of DJ horizontal-well development; average rates are relatively low, most likely driven by the early-stage limitations of sliding-sleeve completions. Only recently have higher-rate jobs been seen.In response to the initial lack of DJ completion changes and the associated apparent lack of effect on production (resulting from production impact being hidden by larger geological changes), the authors developed a petrophysical work flow in an attempt to capture some of these geological parameters and assign them to every horizontal well. This led to calculation of the hydrocarbon pore volume (HPV), a proxy for bulk rock quality, for each of the wells. The conclusion was reached that any statistical model built only on completion parameters will be insufficient and will have to rely on a combination of completion and petrophysical/geological parameters.
Owens, Matt (Extraction Oil & Gas) | Silva, Jesse (Extraction Oil & Gas) | Volkmar, Matt (Extraction Oil & Gas) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services) | Losacano, Tony (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
Abstract The Denver-Julesburg Basin has been going through a new cycle of development with horizontal drilling and high-intensity hydraulic fracturing. Since the first horizontal wells in 2008, more than 4,000 horizontals have been drilled, leading to a four-fold production increase between 2008 and 2012. While completion practices have been fairly similar across the basin over these early-development years, several operators are now starting to experiment with different completion designs. The objective of this paper is to discuss the benefits of these new designs and further evaluate what completion changes deliver the most "bang for the buck" in a challenging pricing environment. Use of a novel completion design and development of a low-cost ultra-low concentration fluid system resulted in significant cost saving while maintaining or improving overall production, thus lowering $/BOE in a challenging industry environment. Lowering cost per BOE drove a process of completion design changes that started with fluid compatibility testing, including regained permeability testing in proppant load cells, which showed that a light and more cost-effective Borate Guar can result in similar or better cleanup than a CMHPG-Zirconate system traditionally used in the DJ basin. Multi-variate analysis results from an extensive petrophysical / completion / production database showed production in the basin predominantly benefits from increase proppant volume and higher stage intensity. Field implementation of this system and a design with more proppant and stage intensity focused on consistently being able to place higher proppant loadings with less polymer. More than 150 horizontal wells were completed between mid-2014 and early 2016 in T5-6N R64-67W while implementing this strategy. When compared to about 350 other horizontal wells, mostly completed without these changes, overall results of the new completion strategy have been very encouraging: Higher injection rates and improved pump time to downtime resulted in a 20+% reduction in days required to complete a typical 8-well pad. Over a period of about 130 pumping days, more than 2,100 frac stages were completed. Supply chain efficiency improvements were implemented to keep up with proppant demand averaging 3.5 million pounds of sand every day, occasionally peaking to above 8 million pounds of sand per day; A new ultra-low concentration Guar Borate system was developed that could be crosslinked at concentrations down to 8 lbs/Mgal. Together with high rate, this fluid system enables placing proppant concentrations up to 6 PPA, making the system significantly cheaper and cleaner than the conventional 20+ lbs/Mgal CMHPG systems that were routinely used in the DJ Basin. Overall production in both Codell and Niobrara was above results for nearby peers over a wide range of production metrics. A petrophysical workflow was developed to arrive at a proper apples-to-apples comparison of historical production response in the area as compared with the results associated with this new strategy. Through various statistical analysis tools such as multi-variate analysis, the authors evaluated the importance of both reservoir and completion changes, and identified several key characteristics that are closely tied to the highest production responses in the DJ Basin.
Miller, Fred (Carrizo Oil & Gas, Now with Navigation Petroleum) | Payne, Jon (Eureka Geological Consulting, Formerly with Liberty Resources) | Melcher, Howard (Liberty Oilfield Services) | Reagan, Jim (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
Abstract The Denver-Julesburg (DJ) Basin has seen oil and gas production for more than a century. It is going through a new cycle of development with horizontal drilling and high-intensity hydraulic fracturing. Since the first horizontal wells in 2008 nearly 4,000 Niobrara and Codell horizontals have been drilled. While completion practices have remained fairly standard across the basin, production results vary wildly. We utilized a high-quality digital log dataset to accurately characterize reservoir quality in the Niobrara and Codell formations in the DJ Basin. The final dataset included 562 digital logs spread across the current extent of horizontal drilling in the DJ Basin. A petrophysical workflow was developed and detailed mapping of the reservoir attributes was completed. The log derived parameters, along with an aeromagnetic and vitrinite reflectance dataset, provided excellent insight into which geologic parameters could be best tied to well production response. Through bivariate and multivariate analyses using reservoir and completion data, and an economic evaluation to determine the "best bang for your buck", we have identified several completion changes for the basin that result in a significant reduction in the cost per bbl of oil produced. While geological parameters have been found to matter greatly for the production success of DJ horizontals, completions matter as well. The high GOR areas of Inner Core Wattenberg benefit most from jobs with more proppant, whereas areas with poorer reservoir quality generally benefit from higher stage intensity and jobs with larger fluid volumes. All suggested completion changes have a major impact on lowering $/boe over the long term and result in lowering incremental cost per incremental boe within a period of only 365 producing days in the current low oil price environment.
Ramurthy, Muthukumarappan (Halliburton) | Richardson, Joe (Bayswater Exploration & Production LLC) | Brown, Mark (Bayswater Exploration & Production LLC) | Sahdev, Neha (Halliburton) | Wiener, Jack (Halliburton) | Garcia, Mariano (Halliburton)
Abstract Hydrocarbon production has been long existent in the Denver Julesburg basin and with the development of horizontal drilling technology the Niobrara has become one of the most economical plays even with lower oil prices. The multi-bench Niobrara formation is the primary target in the basin followed by the Codell. Even with the better economics, the Niobrara and the Codell completions are not optimized yet. The operators are still aiming for more and more stages with lesser spacing thus increasing the costs. The objective of this study is to show that stage spacing can be optimized with low cost diversion technology yielding equal or better production with fewer stages thus lowering costs. In this optimization study, two Niobrara "C" bench lateral wells from the same pad that are next to each other were selected as candidates. The first well, Well-K was completed with 28 stages geometrically spaced at 153 feet utilizing the perf-n-plug methodology. The second well, Well-L was completed with 20 stages, geometrically spaced at 215 feet, also utilizing the perf-n-plug methodology. Well-L was stimulated utilizing the intra-stage diversion process and had approximately 404,000 lbm less proppant than Well-K. Well-K was completed without the diversion technology. Following stimulation and flowback, Fibercoil with Distributed Temperature Survey (DTS) and Distributed Acoustic Survey (DAS) capabilities were run in both the wells to diagnose the contribution from each perforation cluster. The Fibercoil results clearly showed that Well-L with larger stage spacing and intra-stage diversion had 80% fracture initiation as opposed to 60% with the limited-entry Well-K that had shorter stage spacing. The production results so far are very encouraging for the L-well. The 180-day cumulative oil production for Well-L is almost similar to Well-K with the normalized barrels of equivalent oil (BOE) per foot, BOE/ft. difference being lower by 3%. This study has clearly shown us that with some additional enhancement intra-stage diversion can be used to optimize stage spacing without compromising production. The post-frac fracture modeling analysis along with the Fibercoil results including warm-back analysis and production for the two wells is presented.
Abstract The use of sliding sleeve completions has been widely recognized as an efficient and effective means of completing horizontal laterals in unconventional reservoirs for several years. Recently, the focus shifted to optimizing stage spacing and number of stages per lateral. Even with such optimization the entire lateral was not effectively stimulated and drained. In this 15-well pad pilot study, we focused not only on optimizing the design but also on achieving uniform drainage along the lateral. A treatment design using biodegradable diverters to split each stage into two proppant cycles was recommended. The diverter was used on 5 of the 14 wells completed. Total proppant and fluid volumes, as well as proppant and fluid types, were the same on conventionally-treated and diverter-treated wells. Average treating rates and operation procedures were also similar over the entire study group. After stimulation, the wells were turned on with identical chokes and produced similarly. Daily oil, gas, and water rates were monitored over eight months and compared. Production was normalized on a cumulative barrel of oil equivalent (BOE) per foot of lateral basis. Results showed the diverter-treated wells produced 28% more than the conventionally-treated wells at eight months, with the margin increasing. Although all wells were completed on the same pad, at the subsurface level they covered over two miles of structurally variable formation. A multivariate analysis incorporating subsurface, drilling, completion, and production properties was also conducted to determine the most important parameters contributing to hydrocarbon recovery. This study shows that diverters can be incorporated in sliding sleeve completions to lower the total cost per BOE and increase hydrocarbon recovery. This diverter design and technology continues to be implemented in projects with success and positive impacts on production.
Abstract A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including: –Enlarged fracture geometry, enhancing reservoir contact –Improved pay coverage through increased fracture height in vertical wells –More thorough lateral coverage in horizontal wells or initiation of more transverse fractures –Increased fracture conductivity compared to initial frac –Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. –Increased conductivity in previously unpropped or inadequately propped portions of fracture –Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] –Use of more suitable fracturing fluids –Re-energizing or re-inflating natural fissures –Reorientation due to stress field alterations, leading to contact of "new" rock Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include: –Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids –Low pressured or fault-isolated wells with limited reserves –Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries –Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
Abstract Low-viscosity slickwater treatments are a popular hydraulic fracturing technique in low permeability reservoirs. Slickwater treatments can provide adequate conductivity in tight gas sand operations at comparatively low costs, and wells treated with low-viscosity slickwater often produce better results than those treated with cross-linked fluids in low permeability situations. Theoretically, proppant transport is poor in low-viscosity slickwater type fluids. Improving the understanding of proppant transport capabilities of slickwater would be beneficial to many operators if the cost or performance were not endangered. Improved proppant transport would result in longer propped fracture half-lengths and more favorable conductivity. Laboratory experiments performed by STIM-LAB, Inc.'s Proppant Consortium show proppant falls from suspension and builds a proppant mound before any form of proppant transport takes place. Clean fluid stages pumped between sand-laden stages were shown to erode proppant from the proppant mound. These results formed the basis for the development of power and bi-power laws to describe the transport. These laws and the results of the laboratory experiments were used to perform sensitivity analysis to determine the relative effects of fluid viscosity, fluid density, pump rate, proppant diameter, proppant density, proppant concentration, and fracture width on slickwater treatments in the field. Using the power and bi-power laws, the resulting sensitivity analysis, and the laboratory observations, experimental slickwater schedules were designed and field tested. A total of five experimental slickwater fracturing treatments were performed. Production data from each experimental slickwater treatment and well were compared to offset data to determine any possible effects from improved proppant transport. Production results from the field trials, including both initial production (IP) rates and early cumulative production totals, indicate significant improvement when compared to offset wells. Introduction Over time, many different names have been used to describe slickwater-type fracturing treatments including river fracs, pit fracs, water fracs, treated water fracs, low-proppant fracs, and friction-reduced fracs. The fluid in slickwater treatments consists of water-only or water with a low linear gel concentration. Low proppant concentrations are typically used (0–2 ppg) and are often ramped. Some water fracs are pumped with no proppant at all. Pump rates can vary widely. There are many reasons that may explain why low-viscosity slickwater treatments are successful including: minimal leak-off in low permeability formations, the absence of gel residue, reactivation of natural discontinuities, optimal dimensionless fracture conductivity, and overall economics.1 Variations of slickwater treatments include hybrids and sweep stage slickwater jobs. Hybrid fracture treatments are defined as a low-viscosity pad pumped to initiate the fracture followed by a heavier, higher viscosity fluid laden with proppant.2 Multiple stage slickwater treatments,3 where stages alternate between clean fluid and proppant laden fluid, are defined as sweep stage type slickwater jobs. The overall objective of the project described in this paper is to improve the understanding of proppant transport mechanisms in low-viscosity slickwater hydraulic fracture treatments. Improved proppant transport may result in longer propped fracture half-lengths, thereby resulting in improved fracture conductivity, and higher production rates. Power and bi-power law equations, developed to describe this type of transport, were used to simulate various slickwater treatment scenarios. Observations from these experiments along with the simulations are used to predict what the resulting proppant mound may look like in a slickwater hydraulic fracture and how it is affected by pumping techniques. A sensitivity analysis was also performed to show the sensitivity of certain variables on proppant mound growth. These variables include: fluid density, proppant density, proppant diameter, fluid viscosity, fracture width, fluid flow rate, and proppant concentration.
Refracturing wells, completed in the Codell formation, has caused a resurrection in activity in the Wattenberg Field of the Denver-Juleseburg (D-J) Basin. HS Resources (HSR) has increased average oil and gas rates by greater than 500% by restimulating over 750 Codell wells. The evolution of applied fracturing fluid technology has played a major role in the success of the Codell refrac program.
This paper will identify and evaluate the benefits to well performance and economics gained from the evolution of fluids used in the Codell refracture program. In this effect, the fluid systems will be compared using treating pressure characteristics, production analysis, fluid properties, and rheological property evaluation via specialized testing apparatus and economic results.
The Codell Sandstone is Upper Cretaceous in age and produces condensate and gas with little water at true vertical depths of 7,000 to 8,000 feet. The Codell is a highly bioturbated marine bar-margin sandstone deposit which was initially over pressured (0.6 psi/ft pore pressure gradient, in the central portion of the field). Bottomhole static temperature ranges from 240 to 260°F across the field with 250°F as the expected average. The Codell is 10 to 20 feet thick and is rich in clay (15 to 25% by volume). Sediment sorting is poor with mixed layer illite/smectite clay occupying pore filling and pore-lining habitats. Trapping is enhanced by regional basement fault trends to the west and north, and an erosional pinchout to the south, southeast and northeast.
Pore volume (porosity x thickness) patterns parallel the erosional edge of the Codell to the southeast of the Wattenberg field. Typical pore volume phi-h values range from 1.5 to greater than 2.0. Pore volume is only important if the value falls below the 1.5 value as exists in the unproductive southeast area of the Wattenberg Field.
The permeability in the Codell interval is very low due to the small and tortuous pore network1. Typically, mercury injection into the core shows that 94% of the rock pores has a radius of one micron or less. Numerous interpretations of post frac permeability have showed the effective permeability ranging from 0.01 to 0.09 md.
Evolution Towards Refracturing
Early activity in the basin consisted mainly of drilling to, and exploiting, the J-Sand formation. The Codell was only completed sporadically until the early 1990's. At that time, the Codell and Niobrara zones were typically completed together in a limited entry treatment2. The primary reason for commingled zone treatment was the favorable economics. Two other treatment styles were also investigated and performed by a variety of operators in the basin: Codell only completions and dual completions in the Codell and Niobrara.
From the extensive analysis of the three types of completions pumped on the Codell and Niobrara it was determined that:
Dual completions in the Codell and Niobrara correlated with higher well productivity.
Production from the limited entry treatments was 5 to 6% lower than the dual completion treatments.
Production from the Codell only stimulations was 20 to 21% lower than the dual completions.