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The emerging Vaca Muerta Formation, located in the Neuquén Basin in Southern Argentina, is the most successful Unconventional Play outside United States. In the last few years, several blocks have initialized multi-rig development programs and operators have identified interference between existing producers and newly fractured wells during the completion. The effect known as parent-child occurs when the reservoir depletion around the parent well modifies the pore pressure and induces variations in the original stress field. As a result of this effect, the parent well could be seriously damaged, the hydraulic fracture of the child well would be less efficient and there will be an unsymmetrical recovery around the child well. The parent-child effect is usually negative and impose an additional challenge on the drilling and completion sequence of the block. This contribution is an attempt to quantify the production impact of this effect using a combination of a multi-disciplinary workflow.
Unconventional reservoirs were originally developed by small oil and gas companies with stand-alone wells spread across the different basins. Later in time when major operators started to develop these projects that requires intensive capital expenditure, the factory mode was deployed to increase operational efficiency. This development strategy requires the adjustment of well spacing and completion designs to minimize well production interference while maximizing the recovery factors and economics. Despite many optimization studies have been looking for the perfect design, the ultimate recovery of wells drilled in factory mode are negatively impacted compared to a stand-alone well. Additionally, as the development of the blocks moved forward, some new wells (child) were placed next to wells on production (parent) and operators have seen an additional negative impact commonly called parent-child. Statistical data from different US Shale Plays confirmed the negative production impact of this effect (
Abstract One of the unique aspects of the US shale boom is that firms have purchased most mineral rights from thousands of small landowners. Though several studies have focused on cross-sectional aspects of these leases, none study their dynamics. Incorporating several aspects of the unique US context, I develop and simulate a model of depletable mineral rights that matches several key aspects of data on leasing and drilling in the US Eagle Ford shale.
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This paper was prepared for the Rocky Mountain Joint Regional Meeting in Denver, Colo. May 27-28, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request providing proper credit is given that publication and the original presentation of the paper.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Industrial shale-oil operations in North America and Europe predated the Drake discovery, but, since then, most have succumbed to competition from petroleum. However, the existence of enormous oil-shale resources in the Green River formation of Colorado, Utah and Wyoming [estimated at over a trillion bbl of shale oil in place] and the advancement of United States oil-shale technology by research and development programs of government and industry during the past 15 years point to a natural partnership of petroleum and oil shale to meet the accelerating energy demands of the future. The utilization of oil shale is not a question of limited petroleum supplies, but one of economics. Two factors are expected to improve the economic outlook for industrial shale-oil production a rise in petroleum replacement cost and further advances in oil-shale technology.
The production of oil from oil shale dates back to the 17th century, when medicinal oils were produced from bituminous shales in England. Shale-oil industries started in France in 1838; in Scotland in 1850; in Australia in 1860; in Estonia, Spain and Manchuria in the 1920's; and in South Africa and Sweden in the 1930's. A small shale-oil industry was operating in Canada and the eastern United States in 1860 but disappeared when petroleum became plentiful following the Drake discovery in Pennsylvania. Industrial operations in other countries generally have had similar experiences; that is, when petroleum became readily available at reasonable, cost, the oil-shale operations could not compete without sizable subsidies. Industrial operations are presently conducted only in Spain, Sweden, Estonia, Manchuria and the U.S.S.R.
Oil shales do not contain oil; instead, they consist of solid, largely insoluble, organic material intimately associated with a mixture of minerals that make up about 85 per cent of an average shale yielding 25 gal of oil per ton. Oil shales are widely distributed throughout the world in sedimentary rocks fray. Cambrian to Recent, but by far the largest known deposit is in the Green River formation in Colorado, Utah and Wyoming.
Lewis G. Weeks in 1959 published a comprehensive analysis and forecast of demand and sources of supply of energy for the next 100 years. He estimated that, in addition to imported petroleum, the United States would use 490 billion bbl of the 570-billion-bbl ultimate reserve of domestic petroleum [including natural gas energy in equivalent bbl of petroleum and oil from tar sands] and 600 billion bbl of shale oil from 1960 to 2059. Although Weeks considered all of the oil-shale deposits throughout the U. S. as sources of shale oil, the 1.132 trillion bbl of potential oil in place in the Green River formation, as estimated by Donald Duncan of the Federal Geological Survey, constitutes almost twice the supply required to meet the need estimated by Weeks.
Gonzalez, Daniel (Chesapeake Energy) | Holman, Robert (Chesapeake Energy) | Richard, Rex (Chesapeake Energy) | Xue, Han (Schlumberger) | Morales, Adrian (Schlumberger) | Kwok, Chun Ka (Schlumberger) | Judd, Tobias (Schlumberger)
Abstract The stress state at infill wells changes as a function of production from the existing producer. Understanding spatial and temporal in situ stress changes surrounding drilled uncompleted (DUC) wells or infill wells has become increasingly important as the industry works through its inventory of DUC wells and redesigns infill wells with an engineering approach. Optimizing infill/DUC well completion designs requires an estimation of the altered in situ stress state. This study presents the concept of a "production shadow" as the stress change in four-dimensional space, affecting well performance and optimal well configurations for pad development. The production shadow accounts for the compound effects from both hydraulic fracture mechanical opening and stress-state alteration from depletion. This paper details an Eagle Ford case study integrating production shadow effects into the parent and infill well hydraulic fracture modeling as well as "frac hit" analysis. The production shadow influences the degree of fracture complexity developed by the infill/DUC well stimulation. Understanding and accounting for the production shadow are critical in engineering to establish and preserve an optimal connection of the induced stimulated fracture network to the wellbore.
Abstract It is not uncommon that wells drilled in shale reservoirs experience a large Initial Production (IP), followed by a significant drop in productivity a few months after hydraulic fracturing, leading to a reduced Estimated Ultimate Recovery (EUR), with primary recovery factors rarely exceeding 15%. This drop in productivity constrains the economics of wells, and entails operators to drill and stimulate more wells to retain a production rate target. Recently, refracturing has emerged as a means to increase the productivity of these wells. Numerous well interventions are required to isolate and perforate new zones in addition to the increased costs associated with fracturing fluids and proppant requirements. This paper investigates the physics of using supercritical CO2 as a secondary recovery method to rejuvenate hydraulically fractured wells in shale reservoirs. Under highly in-situ compressive stresses, diagenesis (fluid release) reactions provoke instabilities within the shale generating high porosity channels parallel to the minimum horizontal compressive stress. These channeling localization instabilities exist in ductile formations and are periodically interspersed in the shale's matrix. Induced hydraulic fractures intersect these channels, invoking pressure drawdown and drives production from these high velocity pillars. These channels close with well depletion, causing a sharp productivity decline. This paper predicts the critical fluid pressure above which pressure should be maintained by CO2 injection to prevent the channels from closing. A computational model was developed for a shale play in Saudi Arabia as a case study. As the in-situ compressional stresses are high and its geologic setting is applicable, the critical fluid pressure is calculated. This paper aims to further the understanding of using CO2 as a secondary recovery technique and helps pave the road for a more sustainable future by sequestering CO2 into the ground and enhancing the EUR of shale oil and gas reservoirs.