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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.
Potapenko, Dmitriy Ivanovich (Member) | Hart, Timothy Brian (Fremont Petroleum Corporation) | Waters, George Alan (Member) | Lewis, Richard E. (Member) | Utter, Robert J. (New Ventures Energy Consulting) | Brown, J. Ernest (Member) | Goudy, Guy Thomas (Formerly Fremont Petroleum Corporation) | Jelsma, Henk H (Radial Drilling Services, Inc.)
Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
The Rumaila Field is in southeast Iraq and contains multiple reservoir intervals, including the Upper Cretaceous Mishrif carbonate reservoir, one of the major reservoirs in the world, that has been producing for more than 50 years. One of the key challenges in the Mishrif is to characterize the pore-structure distinction between primary and secondary porosity. The secondary porosity in the form of large pores, if present, dominates the petrophysical properties, especially permeability. Advanced logs, e.g., nuclear magnetic resonance (NMR) and image logs, can be used to understand the variations in pore structure, both qualitatively and quantitatively. In this paper, we focused primarily on four new wells with very comprehensive logging and coring programs. NMR logs were acquired using different tools and pulse sequences. This resulted in uncertainty in porosity and T2 distributions and, consequently, complications in the NMR interpretation. We observed two key issues: porosity deficit due to lack of polarization and T2 distribution truncation due to the low number of echoes. We used a single pore model to reproduce the NMR response in different pore sizes and fluid types for different pulse sequences. The results showed that the NMR response, especially in water-filled (water-based-mud filtrate) large pores, is sensitive to polarization time, echo spacing, and tool gradient strength. NMR log data confirmed the modeling results. We recommended an optimum pulse sequence and tool characteristics to fully capture the heterogeneous rock and fluid system in this carbonate reservoir. NMR logs, when available, were the primary tools to identify the large pores. We present a consistent workflow for NMR log analysis that was developed to identify and quantify large pores and extended to all wells in the field. We used advanced NMR interpretation techniques, e.g., factor analysis (NMR FA) (Jain et al., 2013), in a series of oil wells drilled with water-based mud. Using factor analysis, we identified a cutoff value of 847 ms for large pore volumes. In this manuscript, we also present an integration of laboratory measurements, e.g., NMR, mercury intrusion capillary pressure (MICP) data, whole-core CT scanning, and thin-section analysis, in our interpretation workflow. We also compared the large pore volume from image logs with NMR logs and other laboratory data and observed very consistent results. All the available information was integrated to build an “NMR-based” petrophysical model for porosity, rock type, permeability, and saturation determination. The NMR-based model was very comparable with the classic flow zone indicator (FZI) rock typing. The results of this study were used to modify the NMR acquisition program in the field and to build a petrophysical model based on only NMR and image log measurements for carbonate reservoirs. In this paper, we will discuss NMR modeling and corresponding log data from various wells to confirm the results. Furthermore, we will present a novel interpretation workflow integrating laboratory measurements and log data, which led to the modification of the NMR acquisition program in the field and the creation of a data-driven petrophysical model based on only NMR and image log measurements for carbonate reservoirs.
Colorado oil production is surging to record levels, outpacing the other major producing US states in year-over-year gains on the backs of the steady-and-predictable Denver-Julesburg (DJ) Basin and overlapping Niobrara Shale. As overall US oil output continues to surge, attention has been drawn to the Permian Basin and SCOOP and STACK plays. Operators have flocked to West Texas, southeastern New Mexico, and central Oklahoma to stake claims to land they believe will usher them into a new, leaner era for the industry. The expansive Permian alone, which covers more than 75,000 sq miles, has accounted for the bulk of US oil production increases and mergers and acquisitions over the last couple of years. Although they are intertwined and together encompass parts of Colorado border states Wyoming, Nebraska, and Kansas, the DJ and Niobrara offer a fraction of the acreage and prospective resources of the Permian.
Chen, Ming (China University of Petroleum, China) | Zhang, Shicheng (China University of Petroleum, China) | Zhou, Tong (Research Institute of Petroleum Exploration and Development, Sinopec) | Ma, Xinfang (China University of Petroleum, China) | Zou, Yushi (China University of Petroleum, China)
Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited‐entry perforation and in‐stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited‐entry perforation for multifracture treatments, but relatively few have focused on the in‐stage diversion process. The design of in‐stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in‐stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in‐stage in‐situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time‐marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in‐stage diversion operations. Parametric studies reveal that the in‐stage in‐situ stress difference is a critical parameter for diversion designs. When the in‐situ stress difference is larger than 2 MPa, the fracture in the high‐stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in‐stage in‐situ stress difference. The diverting time should be earlier for formations with high in‐stage stress differences as well. Adding more perforation holes in the zone with higher in‐situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in‐stage diversion and optimize the diversion design timely.
Distributed acoustic sensing (DAS) inter-stage vertical seismic profiling (VSP) data were acquired during the stimulation of two horizontal shale wells in the Denver-Julesburg (DJ) Basin’s Hereford field. These data were analyzed to obtain induced fracture heights and fracture densities for use in fracture modeling and Stimulated Rock Volume (SRV) calculations. Inverted inter-stage VSP (also referred to as rapid time-lapse DAS VSP) data, transformed to an anisotropic seismic velocity model via rock physics relationships, were used to estimate stage-by-stage fracture height and density. Comparison of fracture height from multiple sources confirm the validity of fracture height calculations for the Niobrara fiber well, and the deeper Codell fiber well. When combined with other independent diagnostics such as microseismic, tilt (microdeformation), seismic rock properties, pressure, and distributed acoustic/temperature sensing (DAS/DTS) data, these estimates are validated for use in developing an optimized completion plan, as well as for use in calculating stage-by-stage stimulated rock volumes.
The Hereford field is located in the northern DJ Basin, Colorado, just south of the Wyoming state line. Similar to the giant Wattenburg field to the south, Hereford produces from the unconventional reservoirs of the Upper Cretaceous Niobrara Formation and the Codell Member of the Carlile Shale (Figure 1). Early in the life of the Hereford field, it was understood that the "complexity of the fracture system" would require significant analysis in order to understand and realize the reserve potential of the field (Anderson et. al., 2015). Early wells in the field, drilled between 2010 and 2012, were completed with relatively small completions and primarily accessed oil in the natural fracture systems. The very tight 0.5 to 3.0 mD permeability in the Niobrara B Chalk requires larger completion rates and volumes to access the matrix oil.
The Hereford Field contains pervasively naturally fractured zones as well as more matrix dominated areas. A production optimization project was initiated by HighPoint Resources in 2019 to understand the best practices for maximizing production from both the pervasively natural fractured parts of the field, as well as the more matrix dominated portions of the field, while performing completions in 23 wells on four pads within the field. This project was designed to shorten the cycle-time needed to optimize completions. Rather than execute well-by-well parameter variations that can take years to evaluate, this project was designed to test numerous completion scenarios with a variety of diagnostic tools in a short period of time. Evaluation of these completion parameter changes give the best chance of success. In addition to distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) on fiber optic cables cemented behind casing, numerous other techniques were utilized to evaluate these wells including surface microseismic, tilt (microdeformation), pressure gauges, micro-imaging, and a pilot well with a quad combo and dipole sonic. Additionally, the 2009-vintage seismic data were reprocessed and merged with adjacent surveys in 2019 including a new pre-stack inversion. (Raw data courtesy of Seitel).
ABSTRACT The Rumaila field is in South East Iraq and contains multiple reservoir intervals, including the Upper Cretaceous Mishrif carbonate reservoir, one of the major reservoirs in the world, that has been producing for more than 50 years. One of the key challenges in the Mishrif is to characterize the pore structure distinction between primary and secondary porosity. The secondary porosity in the form of large pores, if present, dominates the petrophysical properties, especially permeability. Advanced logs e.g. Nuclear magnetic resonance (NMR) and image logs can be utilized to understand the variations in pore structure both qualitatively and quantitatively. In this paper we focused primarily on four new wells with very comprehensive logging and coring programs. NMR logs were acquired using different tools and pulse sequences. This resulted in uncertainty in porosity and T2 distributions and consequently complications in the NMR interpretation. We observed two key issues: porosity deficit due to lack of polarization and T2 distribution truncation due to the low number of echoes. We used a single pore model to reproduce the NMR response in different pore sizes and fluid types for different pulse sequences. The results showed that the NMR response, especially in water (water-based mud filtrate) filled large pores, is sensitive to polarization time, echo spacing and tool gradient strength. NMR log data confirmed the modelling results. We recommended an optimum pulse sequence and tool characteristics to fully capture the heterogeneous rock and fluid system in this carbonate reservoir. NMR logs, when available, were the primary tools to identify the large pores. We present a consistent workflow for NMR log analysis that was developed to identify and quantify large pores and extended to all wells in the field. We used advanced NMR interpretation techniques e.g. Factor Analysis (NMR FA, Jain et al, 2013) in a series of oil wells drilled with water-based mud. Using Factor Analysis, we identified a cut off value of 847 ms for large pore volumes. In this manuscript we also present an integration of laboratory measurements e.g. NMR, mercury intrusion capillary pressure data, whole core CT scanning and thin section analysis in our interpretation workflow. We also compared the large pore volume from image logs with NMR logs and other laboratory data and observed very consistent results. All the available information was integrated to build an "NMR-based" petrophysical model for porosity, rock type, permeability and saturation determination. The NMR-based model was very comparable with the classic FZI rock typing. The results of this study were used to modify the NMR acquisition program in the field and to build a petrophysical model based on only NMR and image log measurements for carbonate reservoirs. In this paper, we will discuss NMR modelling and corresponding log data from various wells to confirm the results. Furthermore, we will present novel interpretation workflow integrating laboratory measurements and log data which led to the modification of the NMR acquisition program in the field and creation of a data-driven petrophysical model based on only NMR and image log measurements for carbonate reservoirs.
Bradenhead pressure, or sustained casing pressure, is pressure build up in the annular space between the surface casing and the next smaller diameter casing string within the wellhead. The objective of the test pad was to determine if increasing the physical flexibility of cement and rotating the casing string to increase displacement efficiency would help improve the cement bond to casing, decrease cement channeling, and help eliminate future bradenhead pressure accumulation. A twelve well pad housed three different cement slurries: four latex-type jobs, four resin jobs, and four foam jobs. A rotating cement head was used to enable mud circulation, dropping plugs, and rotating the string of casing during the cementing process on two of the four wells of each slurry type. For the production casing string, a threaded and coupled connection with a wedge thread profile was used to withstand the high torque experienced during rotation operations. Results were determined by evaluating pre-and post-stimulation logs along with continued bradenhead pressure monitoring. According to the outcomes from this test pad, recommendations were made on cementing practices within the Denver-Julesburg (DJ) Basin, based on regional gas-oil ratios (GOR). This interdisciplinary work determined whether the deployment of advanced cement slurries and casing rotation would help eliminate a potential health, safety, and environment (HSE) risk and help improve well integrity as related to bradenhead pressure.
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.
Kosters, Bryan (APEX Petroleum Engineering LLC) | Shaw, Kevin (APEX Petroleum Engineering LLC) | D'Souza, Shodan (APEX Petroleum Engineering LLC) | Clark, Justin (APEX Petroleum Engineering LLC) | Besler, Monte (FRACN8R Consulting, LLC) | Barham, Michael (Helis Oil & Gas Company, LLC)
In the era of unconventional oil and gas drilling, time constraints often fast-track projects that lack sound completion practices. A multi-year production study of the Codell Sandstone in Laramie County, Wyoming has developed better completion practices that improved production and Estimated Ultimate Recovery (EUR).
Helis Oil and Gas Co., LLC formed a team of experts to identify and execute best completion engineering practices for their horizontal Codell wells. Utilizing data from the production study and leaning on experience, the team identified seven core areas for improving Codell completions. The team (1) recommended performing fracture diagnostics, (2) investigated methods to increase Stimulated Reservoir Volume (SRV), (3) optimized the job size, (4) reviewed proper chemical additive selection, (5) included on-site real-time micromanagement of treating pressure, (6) reviewed wireline procedures, and (7) performed post-fracture treatment analysis.
The Laramie County comparative study included 247 wells completed during the 4-year time period of 2014 to 2018. Helis Oil and Gas Co., LLC completed a total of 13 wells with the enhanced workflow. Considering normalized average cumulative production per well metric, Helis wells outperformed offset wells by 58% in the first 6 months of production. Extending the time frame to the first 12 months of production, on average, the Helis wells produced 75% more oil. A total of 5 Helis wells outpaced the P10 normalized production curve within the first year of production. Examining normalized decline curves, Helis wells continued to outperform. Furthermore, 10 of the 13 Helis wells outperformed the P10 normalized decline curve after 12 months of production.
These techniques help get out of the mindset of the cookie cutter approach with assembly line frac designs. Focusing on these core principles and systematically applying engineered completion techniques to the Codell workflow has helped Helis Oil and Gas Co., LLC achieve superior production and outperform all other operators in the area.