Case History of Successfully Water Flooding a Fractured Sandstone

Abstract

By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project. Introduction The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit. Gas Injection A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years. JPT P. 1233ˆ

Salinity and pH effects on water–oil–calcite interfaces by using molecular dynamics

“…Smart water (SW) injection stands out as an EOR promising technology that increases recovery factors. [2][3][4][5][6][7][8][9][10][11] EOR based on SW injection is characterized by adjusting water salinity to alter the oil-water-rock interaction. SW ions can interact with rock surfaces and crude oil, which leads to several effects that can improve crude oil recovery.…”

“…Smart water (SW) injection stands out as an EOR promising technology that increases recovery factors. 2–11…”

Optical measurements of oil release from calcite packed beds in microfluidic channels

“…Different IOR strategies are being explored to retrieve more oil (while also minimizing the ecological footprint of the recovery process itself). Most common are methods based on water injection (Goolsby and Anderson 1964;Rausch and Beaver 1964;Hussain et al 2013;Esmaeili and Maaref 2019), for which different strategies are followed: adding alkali, polymers, surfactants or nanoparticles, or adjusting the ion composition. The latter, also known as Smart Water Flooding (SWF) is a relatively recent technique which has been reported to give higher yields than conventional (sea) water injection, (Bernard 1967) in both sandstone (Tang and Morrow 1999;Morrow and Buckley 2011) and carbonate (Gupta et al 2011;Yousef et al 2011;Shehata et al 2014;Nasralla et al 2016Nasralla et al , 2018 reservoirs.…”