Measuring Engineered Oil Recovery
Authors: Sloat Benjamin F. 
Published: December 2007

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering.

Introduction

In the early 1960's, it was possible to drive from Bartlesville, OK, to Iola, KS, and pass just about every type of improved oil recovery process knownto man' North of Dewey, OK, at Post Oak:, CO2 was going into a Bartlesvillesand along with water. The two were mixed at the injection-well perforations. At the other end of the gauntlet, the Layton brothers were running afull-fledged fireflood in a shallow shoestring sand. In between were steamhuff'n'puff efforts, a miscible-gas project, an alkaline extraction (in Missouri), and a couple of polymer projects at Neosho Falls and Benedict Ranch, KS.

The U.S. Bureau of Mines in Bartlesville was working on ways to stimulatewater entry into tighter formations by adjusting wettability, and the Kansas-Oklahoma Water-flood Assn. was active with field trips and barbecues. More than a few operators did their own core work, relying on severallaboratories in the area to monitor the quality of all the water going into andcoming out of the ground. There was even a straight surfactant project a littlefarther west at Batesville in Woodson County, KS.

During that era, oil was selling for $1.85/ bbl at the local refinery andsuch things as government incentives, cost recoupment programs, and tax breakswere unheard of. Waterflooding, which had been imported from Pennsylvania byway of the IIlinois basin, was a mainstay of the local producers.

Although some tried to shoot and complete injection wells selectively tocounter permeability variations, most put water into the ground, pumped off thewells until the project hit its economic limit, and then shut down and moved tothe next reservoir. The feeling was that an unlimited supply of floodcandidates existed, so attention was focused on rate of return rather thanrecovery efficiency.

Enter the 1990's

With our industry's 30 years of EOR experience and with the emphasis now ongetting the most out of existing reserves, it's time to look at what has beenlearned and to make sure that new projects benefit fully from those earlyefforts put into effect when the Intl. Petroleum Exposition was still theindustry trade show and Tulsa the "Oil Capital of the World."

Three real-time measurements are needed on every oil recovery project: theinjectionside factors for pressure and volume; reservoir conditions that relateoil recovery and volume swept; and production-side responses for water, oil, and total recovery. Each segment can be plotted, and although myriad variationsexist, my intent is to show how the more commonly used data are arranged andpresented so that the relative performance of one project can be compared withanother.

Figs. 1 through 3 are typical curves for wateroil ratio (WOR) vs. cumulativeoil recovery, for Hall slopes, and for what ties the two together, cumulativeinjection vs. cumulative oil recovery. Each is explained and then matched withan example to illustrate its value as a measuring tool for a particularengineered-oil-recovery process.

Let's start with the production side, which is where the revenue comes fromand where the bulk of the expense is often concentrated. Fig. 1 (from Ref. 2)is a type curve for a producing well, a group of wells, or even a field thatrelates oil production and the producing WOR. Cumulative oil is measured on thex axis with WOR on the semilog scale. Economic limits can be shown easily, andbecause the area under the curve represents total water production, everythingthat is necessary, to track the response of a well from the time it is firstput on production until it is finally plugged out is in plain view.

Curve A of Fig. 1 represents a very inefficient recovery effort with earlywater breakthrough, low oil recovery, and a quick demise of the well or theprojects. The U.S. is full of such projects, where the secondary/primaryoil-recovery ratio is below 0.5 and, as a result, oil recovery efficiency isaround 25%.

Curve B represents normal waterflood performance, characterized by asecondary/ primary ratio of 1.

JPT

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