Entity

Time filter

Source Type

United States

Lamb A.P.,Boise State University | Lamb A.P.,Colorado School of Mines | Liberty L.M.,Boise State University | Liberty L.M.,Colorado School of Mines | And 4 more authors.
Leading Edge (Tulsa, OK) | Year: 2012

The Upper Arkansas Valley in the Rocky Mountains of central Colorado is the northernmost extensional basin of the Rio Grande Rift (Figure 1). The valley is a half graben bordered to the east and west by the Mosquito and Sawatch ranges, respectively. The Sawatch Range is home to the Collegiate Peaks, which include some of the highest summits in the Rocky Mountains. Some Collegiate Peaks over 4250 m (14,000 ft) from north to south include Mount Harvard, Mount Yale, Mount Princeton, and Mount Antero. The Sawatch range-front normal fault strikes north-northwest along the eastern margin of the Collegiate Peaks and is characterized by a right-lateral offset between the Mount Princeton batholith and Mount Antero. This offset in basin-bounding faults is accommodated by a northeast-southwest dextral strike-slip transfer fault (Richards et al., 2010) and coincides with an area of hydrogeothermal activity and Mount Princeton Hot Springs. This transfer fault is here termed the Chalk Creek fault due to it's alignment with the Chalk Creek valley. A 250-m high erosional scarp, called the Chalk Cliffs, lies along the northern boundary of this valley. The cliffs are geothermally altered quartz monzonite and not chalk. These cliffs coincide with the Chalk Creek fault, whose intersection with the Sawatch range-front normal fault results in a primary pathway for upwelling geothermal waters. © 2012 Society of Exploration Geophysicists. Source


West D.R.M.,SIGMA3 | Harkrider J.D.,SIGMA3 | Besler M.R.,FRACN8R Consulting | Barham M.,Helis Oil and Gas Company | Mahrer K.D.,SIGMA3
SPE Drilling and Completion | Year: 2014

Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope field, production as much as 50 to 75%. To achieve these results, Helis Oil and Gas Company formed a multidisciplinary team in 2008 that was tasked with evaluating and overhauling its completion approach. Pre-2008 completions followed conventional wisdom: Target the Middle Bakken formation between the Lodge Pole and the Three Forks formations. Pre-2009 wellbore constructions included "kick outs" (i.e., multilaterals); openhole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals; and they were erratic and inconsistent. The designs and procedures resulted in a high percentage of premature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 BOPD with an estimated ultimate recovery (EUR) of 300,000 bbl of oil equivalent. During the pre-2009 period, three Three Forks were completed, and these wells produced, on average, 550 BOPD. After evaluating the pre-2009 results, the team recommended ten Changes: (1) change landing target to the Three Forks; (2) increase lateral lengths approximately two-fold from short laterals ("640s") to long laterals ("1280s"); (3) increase formation contact (completion method, stage lateral length, and perforation spacing/density); (4) refine pumpdown operations; (5) implement critical-fracturing-mechanism diagnosis; (6) incorporate proppant selection (ceramic vs. sand); (7) refine flush procedure to include monitoring and ensure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment-fluid design (25-lbm gel loading instead of 40-lbm gel loading); and (10) implement flowback and flow-rate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 "1280s" during 2010-2012. These wells resulted in approximately 1,500 BOPD with a maximum of 2,500 BOPD and EURs of approximately 1.2 million BOE. They are among the best wells in the Williston basin. In comparison, direct-offset- well EURs averaged less than 750,000 BOE. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making dramatic, unfounded changes ultimately optimized production in this Bakken project. Copyright © 2014 Society of Petroleum Engineers. Source


Ouenes A.,SIGMA3 | Aissa B.,SIGMA3 | Boukhelf D.,SIGMA3 | Fackler M.,SIGMA3
Society of Petroleum Engineers - SPE Western North American and Rocky Mountain Joint Meeting | Year: 2014

To reduce our dependence on microseismic data which is only available in about 5% of the shale wells, a recently developed workflow based on "hard" Geophysical and Geological data is used for the estimation of SRV and its varying rock properties in a reservoir simulator. This workflow relies on the use of the concept of Shale Capacity which encompasses the four key shale drivers responsible for most of the factors affecting the shale well performance: TOC, Brittleness, Fracture Density and Porosity. The shale capacity is available over the entire 3D reservoir volume and is estimated from well and seismic data. The SRV varying enhanced permeability is estimated through the use of a variable Half fracture length, a radial function and the shale capacity thus providing a realistic distribution and values to the reservoir simulator. Using appropriate gridding techniques such as the Tartan grid for the SRV cells, near-wellbore effects are accounted for along with no-Darcy effects and gas desorption in the shale reservoir. With these key factors represented in the dynamic model around the well, a Haynesville gas, water rate and pressure was successfully matched without the need for any major history matching effort. The resulting irregular and asymmetric SRV region and pressure distribution takes into account the geologic variability which has major implication on the EUR and well spacing. When comparing the EUR estimated from the derived geologically constrained model and those computed from traditional decline curve analysis, shale operators could be booking reserves that could be 50% lower than the actual ones. Finally, the spacing of the laterals could be optimized by taking into account the resulting irregular and asymmetric pressure distribution around the shale wells. Copyright 2014, Society of Petroleum Engineers. Source

Discover hidden collaborations