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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.
Sochovka, Jon (Liberty Oilfield Services) | George, Kyle (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services)
Abstract The shale industry has changed beyond recognition over the last decade and is once again in rapid transition. While we are unsure about the nature of innovations to make US shale ever more competitive, we are certain that the current downturn will drive a further reduction in $/BO – the total cost to lift a barrel of US shale oil to the surface. As a result of an increase in scale and industry efficiency gains, the all-in price charged by service companies to place a pound of proppant downhole has come down from more than $0.50/lb in 2012 to about $0.10/lb today. In this paper, we discuss what components have contributed to this reduction to date and use several case studies to illustrate the potential for further cost reductions. The authors used FracFocus data to study a variety of placement and production chemicals for about 100,000 horizontal wells in US liquid rich basins, including the Williston, Powder River, DJ, Permian basins, as well as SCOOP/STACK and Eagle Ford. All chemicals used were averaged on a per-well basis into a gallon-per-thousand gallons (gpt) metric. In the paper, we first provide an overview of trends by basin since 2010 for these chemical additives. Then, we perform Multi-Variate Analysis (MVA) to determine if groups of these chemicals show an impact on production performance in specific basins or formations. Finally, through integration of lab testing (on fluid systems and proppants), a liquid-rich shale production database and FracFocus tracking of industry trends, the authors developed a list of case histories that show modest to significant reductions in $/BO. In this paper we focus on proppant delivery cost – the cost to place a pound of proppant in a fracture downhole, where it can contribute to a well's production for years to come. The last decade saw a 10-fold increase in horsepower, a 20-fold increase in yearly stages pumped and a 40-fold yearly proppant mass increase. One result of this increase in scale, was a gain in efficiencies, which led to an average 3-fold fracturing cost decrease to place a pound of proppant downhole. We will document this trend in detail in the paper. A significant industry trend over the last decade has been a "viscosity for velocity" trade. The change to smaller mesh regional proppants, in combination with an increase in pump rates on frac jobs in the US, has allowed fluid systems to become more "watery". At the same time, the industry is moving from guar systems to polyacrylamide-based systems that exhibit higher apparent viscosities at low to ultra-low shear rates. These newer High Viscosity Friction Reducer (HVFR) systems show superior proppant carrying capacity over traditional slickwater fluid systems. Regained conductivity testing has shown that these HVFR systems are generally cleaner for fracture conductivity than guar systems. Along with changes to base chemistry, a 2- to 5-fold increase in disposal costs and an overall "green initiative" over the last decade have resulted in a push to maximize recycled water usage on these HVFR jobs. These waters can be in excess of 150,000 TDS (Total Dissolved Solids) which present challenges across the board when designing a compatible fluid system that fits the needs in terms of viscosity yield, scale inhibition and microbial mitigation etc. – all while keeping costs low. Specialty chemicals, such as Hydrochloric Acid (HCl) substitutes that have similar efficacy as HCl but significantly lower reactivity with human skin, have helped significantly to improve operational safety around previously-categorized hazardous chemicals, and have helped reduce cost and improve pump time efficiency. Measurement of bacterial activity during and after fracture treatments can help with the best economic selection of the appropriate biocide. These simple measurements can help further reduce what is spent on the necessary chemical package to effectively treat a well. This paper provides a holistic view of fluid selection issues and shows a real-data focused methodology to further support a leaner approach to hydraulic fracturing.
The objective of this paper is to highlight the preconceived notions that both ultra-low polymer cross-linked gels and high viscosity polyacrylamide fluid systems are difficult to work with or damaging to formations. The paper discusses when such systems are beneficial as well as define some design restrictions. Historically these types of fluid systems have fallen into a gray area of technology that have now become accepted by some operators in the current low-cost market.
The fluids technology discussed in this paper have blossomed not solely because of their technological advancement, but also due to the market. Industry downturns have forced operators and service companies to find more cost-effective means to stimulate the reservoirs in question. This paper examines the use of these new systems in two regions (Williston and DJ Basins), where hundreds of wells have been pumped with these new systems as well as regained conductivity tests performed in 3rd party labs. We also compare production results of thousands of stages pumped with these new systems versus a more traditional approach.
Over the past decade the DJ Basin has be primarily been stimulated with high-priced low pH zirconate CMHPG fluid systems, as a result of the notion that they leave less residue in the fractures. However, with the very cost sensitive market and the new ultra-low polymer systems testing with higher regained conductivity than the incumbent system, change was inevitable.
In the Williston Basin high rate slickwater jobs have become more commonplace. Hybrid designs have been used to increase proppant loadings. However, a new trend to use significantly higher FR concentrations to achieve a system capable of placing higher proppant concentrations is gaining market share.
This leads to the current obstacles for both systems’ further use in the field. These obstacles are threefold: The notion that the system is contaminating the proppant pack with residue. Lab testing shows this not to be the case. Reconditioning field personnel to run the new systems as designed. Ensure that these systems are not used in designs that do not fit the operational criteria without understanding the limitations.
The notion that the system is contaminating the proppant pack with residue. Lab testing shows this not to be the case.
Reconditioning field personnel to run the new systems as designed.
Ensure that these systems are not used in designs that do not fit the operational criteria without understanding the limitations.
The success of all of these items remain attached to the final product, a well producing as much as, or more, for a lower total cost than the more traditional method.
This paper uses data from the lab and field to challenge many of the preconceived notions about what it takes to successfully place a solid stimulation package. Also, it will address how some of the largest barriers to new technology are predominantly mental, while the new products are technically sound and economically superior.
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.
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.