to prevent further precipitation, the fluid samples were analyzed to determine the concentration of aluminum and silicon (below). Changes in effl uent composition provided infor- mation about the type and morphology of reactive minerals in the core. The Virtual Lab simulator matched the fl ow-test results, providing the mineral surface area and permeability- porosity relationship.
The acid treatment did not deconsolidate the
Heidrun fi eld core and did not form precipitates, indicating that this treatment fl uid was compati- ble with the native mineralogy.15
It also provided the desired permeability improvement.
Productivity in this zone declined after formation-water breakthrough, and worsened after a scale-inhibitor squeeze treatment. Design of a matrix-stimulation job was diffi cult because this was the fi rst well in the Tilje forma- tion to be acidized. The formation was heterogeneous, with high clay content and large clay clasts (bottom).
0.25 0.20 0.15 0.10 0.05 0
First Use of Simulator for Stimulation Statoil operates the Heidrun fi eld, located in the Haltenbanken area of the Norwegian Sea, 120 km [75 miles] south of the Arctic Circle. The target well, A-48, had a deviation angle of 48° across the producing interval in the Tilje forma- tion and was completed with an openhole gravel pack.16
The fi rst use of the Virtual Lab geochemical simulator was for a treatment in the Heidrun A-48 well. The software simulated both batch- reactor and core-flow tests specific to the Tilje formation and provided the parameters needed for a stimulation model. The team simulated sev- eral treatment scenarios and several acid formulations to optimize the fluid types, sequences, volumes and injection rates.17 The core test described earlier in “ From
Fe Si Na
100 200 300
10
Brine HCI-acetic acid 15
20
9/1 mud-acid stage 25
Injected volume, pore volumes
> Core- ow test. The permeability response to treatment acids is measured during a Heidrun eld core test. The increasing permeability during the NH4Cl brine ush following the 9/1 mud-acid treatment indicates movement of nes out of the core (bottom). The upper plot shows elemental concentrations in the ef uent. After changing injection uids, the permeability change is seen before an ef uent effect because the new uid has to pass through the core. All the solid lines are best- t results from the Virtual Lab model, providing essential parameters for modeling the treatment.
Brine 30
ClayACID stage 35
40 0 Al
Laboratory to Field” showed that permeability increased during the ammonium chloride flush that followed injection of the 9/1 mud acid. This indicated continuing movement of fines out of the core. However, in the fi eld, continued fl ush- ing would move those fines deeper into the formation, causing damage when the fl ow slowed or stopped and the fines settled. A flowback stage was included after the mud-acid stage to clear the mobile fi nes out of the formation. The treatment design was based on the core and reactor tests.18
During the treatment, Statoil A A’ B B’ AA’ BB’
> Clay clasts. The Tilje formation in the Heidrun eld contains large clay clasts, apparent in the computed tomographic image (left). The section AA’ includes large, dark, clay clasts (center). The lower section BB’ shows clay laminae (right).
64 Oilfi eld Review
captured samples from all fluid returns and determined the profi le of ions in these fl uids at each stage. With this information, Virtual Lab software confi rmed that fi nes migration was the most likely primary damage mechanism and allowed the operator to examine the possibilities of combined damage mechanisms. This simula- tion showed that the final design improved permeability while limiting mineral precipitation (next page, top). The model recommended injec- tion rates that could not be maintained during execution because of operational difficulties. A second run of the model using actual fl ow rates and fl uid volumes indicated that the difference in fluid placement between the recommended and executed procedures was minor. Before the stimulation treatment, the well productivity index was 20 m3/bar-d [9 bbl/psi-D] and reached 55 m3/bar-d [24 bbl/psi-D] immedi- ately after the treatment. The productivity index over the next seven-month period averaged 42 m3/bar-d [18 bbl/psi-D]. The acid treatment successfully removed the near-well damage and controlled fi nes migration (next page, bottom). The Virtual Lab model optimized after treating
15. An acid treatment normally dissolves some cement; deconsolidation indicates that so much cement dissolved that the core matrix was no longer competent.
16. Ziauddin et al, reference 14. 17. Ziauddin et al, reference 14. 18. Ziauddin et al, reference 14.
Concentration, mol/kg
Permeability, mD
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