Cyclic injection is a process that improves waterflooding efficiency in heterogeneous reservoirs. The concept of cyclic injection is based on (1) pulsed injection and (2) alternating waterflood patterns. Cyclic injection has been successfully applied in a number of sandstone and carbonate oil fields in Russia. In the rest of the world, pulsed injection has had limited application, and only in naturally fractured reservoirs. Although changing the waterflood patterns is a common approach to deal with increasing water cuts, a more systematic approach with both pulsed injection and alternating flow directions is not.Cyclic injection has the greatest potential for improved recovery in heterogeneous, high-permeability-contrast sandstones and in naturally fractured carbonates and dolomites. The efficiency of the process is high in preferentially water-wet rocks saturated with compressible fluids. Capillary pressures and relative permeability effects are responsible for the improved cyclic oil displacement at the micro level. Improved sweep of the less permeable layers in communication with more permeable thief zones, better horizontal sweep achieved by changing waterflood patterns, and alternating the dominance between gravity and viscous forces are the key effects of cyclic injection on the macro level.The potential of cyclic injection at the Lower Tilje/Åre formations of the Heidrun Field in the Norwegian Sea has been evaluated. Some of the reservoir levels are highly heterogeneous, with large permeability contrasts vertically and horizontally. The current drainage strategy for these formations is water injection, with gas lift in producers when needed. Cyclic injection will improve waterflooding efficiency at virtually zero additional cost. Improved sweep, accelerated oil production, and reduced water cut are the main positive effects expected from cyclic waterflooding. The reserves are predicted to increase by 5 to 6% from the targeted reservoirs at Heidrun after 10 years of cyclic waterflooding.

No abstract

Giant, geologically complex heavy oil fields can take decades to develop, sodevelopment decisions made early in the life of the field can have long-rangeimplications. Decision and risk analysis (D&RA) is often used to makedecisions that will maximize risk-adjusted economic benefit. Unfortunatelyin large heavy oil fields, D&RA can be very challenging due to the largenumber of variables and the endless number of development and expansionscenarios to analyze. The time needed to complete a D&RA can becomeprohibitive when full-field reservoir simulation is the main tool forforecasting primary production and well count, with one simulation taking manyhours or days to complete. This paper describes two new simulation tools developed to overcome thesechallenges: 1) a method for populating a model with hundreds-to-thousands ofhorizontal wells, and 2) a method to quickly and directly optimize expansiondecisions. A semi-automated spreadsheet-and-simulation method was developed to quicklyplace and select hundreds-to-thousands of hypothetical/future horizontal wellsin a multi-million grid- block model. Because the method automaticallyaccounted for all model static properties and their effects on dynamicproduction response, the hypothetical wells had productivity characteristicsvery similar to actual drilled wells placed in the model. A multi-variant non-linear interpolation method was developed that enabledfull-field forecasts - for any combination of acreage allocation, well count, drilling order, and expansion rate constraint - to be calculated in less than 5seconds, compared to about 20 hours for traditional simulation. Extensivevalidation work showed that well count and production curves from thespreadsheet virtually overlaid those obtained using traditional simulation ofthe particular expansion scenario. Such close agreement was possiblebecause the basis of the spreadsheet forecast was utilization of traditionalsimulation forecasts from a handful of relevant cases. A key breakthrough beyond just fast forecasting was the coupling of thefollowing three components inside the same spreadsheet: the fast forecastingmethod, calculation of an economic indicator/objective function (NPV), andcommercial optimization tools. This linkage made possible, perhaps for thefirst time (at least at this scale), realization of direct optimization of anydevelopment scenario in a matter of minutes to a few hours, depending on thenumber of variables being optimized. Introduction The field of interest was areally very large and vertically geologicallycomplex, with multiple stacked reservoirs. Rock and fluid propertiesvaried significantly with reservoir, depth, and areal location. The crudewas very heavy, and an expensive processing facility was required for transportand marketing. The oil in place was large enough that the reserves werelimited primarily by the capacity of the processing facility (Fig. 1) and theduration of the production agreement (assuming a sufficient number of economicwells could be drilled to fill the facility). Early in the field life, there was the possibility of expanding theoperation by building a second facility. One of the critical decisions wasthe size of the second facility. Because it was early in the life of thefield, there was little production history and the field was not fullydelineated. Therefore, there remained significant uncertainty in reservoirperformance and thus in the number of wells required to fill a secondfacility. The situation certainly called for D&RA, but the decision tree wascomplex, comprising over 100 branches. The traditional solution would havebeen to run multiple full-field simulation cases to attempt optimization ofeach branch of the decision tree. However, that approach would have beennearly impossible to complete, because each simulation took a day to run (evenusing parallel processing and a dozen cpu's) and optimization would have been atrial-and-error process.

An unconventional thin-bed analysis based on logs, core and miniperm data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea. More than half of the reservoir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements, P. 815

An unconventional thin-bed analysis based on logs, core, and miniperm data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea. More than half of the reservoir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements. Fig. 1-Core photographs showing sand-rich "light… and mudrich "dark… layers, interbedded at the centimeter scale, in a heterolith from the Heidrun Åre bayfill section. The left set was taken under white light; the right was taken under UV light.