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Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft.
Michael Eberhard, an SPE Distinguished Service Award recipient and former director of the SPE Rocky Mountain Region, died 23 June. Eberhard started his 40-year oil industry career as a field engineer for Halliburton Services. He went on to become the company's Rocky Mountain Technology Manager from 2004 to 2011 and led a multidisciplined team focused on unconventional resources completions and optimization. He was the completions manager for Anadarko Petroleum's DJ Basin program from 2011 to 2015. He joined SRC Energy in 2015 and was the COO and executive vice president of the company.
The World Economic Forum's (WEF) Human Capital initiative has been implemented at Satbayev University (SU), Almaty, Kazakhstan, during the last 2 years. Participating in this effort are Chevron, Eni, Shell, and the Colorado School of Mines (Mines). The complete paper assesses the effectiveness of project components, such as industry guest lectures, summer internships, and program improvement, and provides lessons learned for human-resource-development initiatives. In most cases, the industry/university alliance is intermittent, short-term, and underdeveloped. The engagement of three stakeholders, such as government, industry, and the university, is the most-successful model of joint performance.
Employment in America's energy technology and services sector increased by an estimated 8,002 jobs in June, a fourth consecutive month of growth, according to preliminary data from the US Bureau of Labor Statistics (BLS) and analysis by the Energy Workforce & Technology Council. The 1.3% growth comes after the sector added nearly 24,000 positions over the past 3 months after hitting a pandemic low of 591,413 jobs in February, according to BLS data. Gains over the past 4 months bring the sector to a net increase of an estimated 9,043 jobs in 2021. Texas far outpaced other energy-centric states in job growth. The state added an estimated 4,400 jobs over the 30-day period--more that the next 10 states combined, including Louisiana (745), Oklahoma (679), Colorado (362), New Mexico (334), California (327), and Pennsylvania (323)--over the same period.
Denver-based Civitas Resources announced today that it is acquiring Crestone Peak Resources in an all-stock transaction. Civitas was formed last month through the announced merger of Denver-Julesburg (DJ) Basin operators Bonanza Creek Energy and Extraction Oil & Gas. On a pro forma basis, the three-way merger will create a firm with an enterprise value of nearly $4.5 billion and a production profile of almost 160,000 BOE/D. Crestone's assets will bring Civitas' position in the DJ Basin to more than 500,000 net acres. In addition, the combination with Crestone is expected to realize nearly $45 million in expected annual synergies.
James Blaney is an engineer on a hydraulic fracturing fleet for Liberty Oilfield Services, and is based in the Permian Basin. He holds a bachelor's degree in petroleum engineering from the Colorado School of Mines (CSM). While at CSM, he was an active member of the CSM SPE Student Chapter. He volunteered regularly at fundraising events and was a member and captain of the CSM PetroBowl team.
Abstract Subsurface characterization of fluid volumes is typically constrained and validated by core analytical fluid saturation measurement techniques (example Dean-Stark or Open Retort methodology). As production in resource plays has progressed over time, it has been noted that many of these methods have a large error when compared to production data. A large source of the error seems to be that water saturations in tight rocks have been consistently underestimated in the traditional laboratory measurement techniques. Operators need improved fluid saturation measurements to better constrain their log-based oil-in-place estimates and forward-looking production trends. The overall goal of this study is to test a new laboratory workflow for fluid saturation quantification. Recent advancements have led to an innovative methodology where a closed retort laboratory technique is applied to samples from lithological rock types in the Williston, Uinta and Denever-Julesburg (DJ) basins. This new technique is specifically designed to better quantify and validate water measurements throughout the tight rock analysis process, as well as improved oil recovery and built-in prediction. A comparison of standard crushed rock analysis employing Dean-Stark saturation methods is compared to the closed retort results and observations discussed. Results will also be compared against additional laboratory methods that validate the results such as geochemistry and nuclear magnetic resonance. Finally, open-hole wireline logs will be utilized to quantify the impact on total water saturation and the oil-in place estimates based on the improved accuracy of the closed retort technique.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
Abstract Leveraging publicly available data is a crucial stepfor decision making around investing in the development of any new unconventional asset.Published reports of production performance along with accurate petrophysical and geological characterization of the areashelp operators to evaluate the economics and risk profiles of the new opportunities. A data-driven workflow can facilitate this process and make it less biased by enabling the agnostic analysis of the data as the first step. In this work, several machine learning algorithms are briefly explained and compared in terms of their application in the development of a production evaluation tool for a targetreservoir. Random forest, selected after evaluating several models, is deployed as a predictive model thatincorporates geological characterization and petrophysical data along with production metricsinto the production performance assessment workflow. Considering the influence of the completion design parameters on the well production performance, this workflow also facilitates evaluation of several completion strategies toimprove decision making around the best-performing completion size. Data used in this study include petrophysical parameters collected from publicly available core data, completion and production metrics, and the geological characteristics of theNiobrara formation in the Powder River Basin. Historical periodic production data are used as indicators of the productivity in a certain area in the data-driven model. This model, after training and evaluation, is deployed to predict the productivity of non-producing regions within the area of interest to help with selecting the most prolific sections for drilling the future wells. Tornado plots are provided to demonstrate the key performance driversin each focused area. A supervised fuzzy clustering model is also utilized to automate the rock quality analyses for identifying the "sweet spots" in a reservoir. The output of this model is a sweet-spot map that is generated through evaluating multiple reservoir rock properties spatially. This map assists with combining all different reservoir rock properties into a single exhibition that indicates the average "reservoir quality"of the formation in different areas. Niobrara shale is used as a case study in this work to demonstrate how the proposed workflow is applied on a selected reservoir formation whit enough historical production data available.
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.