Shell/Maersk Models
(Ovens and Niko, Ovens et. al)

 

Basic Description of the Model^,[1]^,[2]

 

The Barenblatt fracture growth criterion is combined with thermal and poroelastic effects and fracture toughness to yield a compact formulation, relating changes in fracture length to changes in fracture pressure.  It is assumed that fractures grow with a constant height.  Two dimensionless parameters are introduced: one relates the magnitude of in-situ stress changes due to thermal and poroelastic effects and one relates to toughness.  The limitations of this model include:

 

Ø      Proximal producers are not considered.  Coupling with a reservoir simulator is necessary for considering injector/producer interaction.

Ø      Flux of water exiting the fracture is uniformly distributed along the length of the fracture.

Ø      It is a two-dimensional, constant height model.

 

Case studies have been published for a number of wells in the Dan Field, in the Danish sector of the North Sea - a low permeability chalk oil field.  The reservoir has a porosity of 20 – 40% but low matrix permeability of 0.5 – 2 mD.  Tectonic fractures are rarely observed except in the immediate vicinity of the main fault.  Several monitoring techniques were applied to evaluate fracture height, length, orientation and injector/producer interaction.  The techniques included openhole and through-casing saturation logging, tracer injection, producer water cut monitoring and falloff surveys in injection wells. 

 

“In general, the observed fracture wing areas are in line with those expected from the model.  However, injectors with higher rates generally require higher permeability to match the field data.  The physical origin of this effect could be the induction of micro-fractures near the plane of the main fracture, which enhances the effective permeability seen by the fracture.”2 

 

This may be due to thermal stress effects because the minimum stress can change orientation during injection.[3]

 

The model is applied, in conjunction with fracture dimension monitoring techniques, to Dan field water injection projects.2  The following is a summary of the monitoring techniques used in identifying fractures.

How to Determine the Orientation of the Fracture?

 

1.       Injection of Radioactive Tracer

“a short lived radioactive g-emitting tracer was injected into the water injectors MFB-07m MFA-09A, MFB-05 and MFB-01, which surround the A-Flank west producer MFB-22.  In addition, a suite of logs including g-ray, was run in the MFB-22 itself.  The g-ray logs were intended to identify the position of the induced fractures intersecting MFB-22 and to determine whether the fractures had multiple branches.”

 

If the injector and producer are both sub-vertical, this method of injection may not work because the fracture may not intersect with the producer.

 

2.       Fractures Intercepted by New Wells

“In the summer of 1996, a new producer, well MD-3B, was drilled on the crest of the A-block.  The well intercepted the fracture created by the injector ME-02, which had been injecting above fracture propagation pressure for some six months.  The open-hole resistivity log from MD-3B clearly shows a waterflooded interval about 150 feet wide.”2 

 

The contrast between the injected water and formation water indicates where the fracture intersects with the producer.  The sharp change could also indicate piston like displacement.

 

How To Determine the Fracture Height?

Temperature logs were used to infer the fracture height along the wellbore.  This technique is questionable, especially after a large volume of water has been injected.

 

Fracture dimensions (length and height) are mainly inferred through pressure matching with numerical model.

 

Does fracture branch?

Three possible methods were suggested for detecting fracture splintering or branching – one is g-ray tracer logging, another is saturation logging and the third is evaluation of the injection pressure signature.  Multiple spikes and new spikes at a later time were suggested to be indications of multiple fractures.  If saturation logging did not indicate swept zone from a single fracture and injection pressure showed a step-like increase, then this was suggested as an indication of multiple fracture growth.  Periods of rapid pressure increase were inferred to be indications of multiple fracture growth.  One needs to be cautious about this because periods of rapid pressure increase could be the indication of fracture tip plugging and sudden growth.

 

Fracture branching has been observed in the pilot injection well through logging the swept zone in a horizontal well about 1000 ft away.  Two swept zones of about 50 feet wide and 100 feet apart were found.