acetic acid to help remove additional CaCO3 and to provide a preflush for the final treatment, which was a 9/1 organic mud acid.22
The Virtual
Lab process provided a means to test the effec- tiveness of this treatment schedule. Reaction kinetic parameters were available in the database. A core-fl ow test on a small plug from the Cromarty formation provided an esti- mation of mineral surface areas and parameters for the permeability and porosity correlation. The test showed that treatment fl uids were com- patible with the native mineralogy and that they increased permeability within the core sample. The next step was to simulate the reservoir geometry using the Virtual Lab software. In this simulation, damage was assumed to be due only to fi nes migration. The model showed that well- bore skin factor declined steadily with the treatment, and a small quantity of amorphous silica reprecipitated near the wellbore (below). A PLT Production Logging Tool run just before the main stimulation treatment was ana- lyzed in real time and indicated no production from the gravel-packed channel sand. The first half of the productive interval beyond the shale section produced oil with a 50% water cut, and the second half produced dry oil at a low rate. Since water was not coming from an isolated zone, it was not possible to stimulate oil produc- tion alone.
The first treatment stage was jetting a chelating agent along the entire wellbore. This stage mechanically cleaned the wellbore and increased the oil production rate to 1,000 B/D [160 m3/d] with a water cut of 40%. Flowback after the treatment was slower than planned because of operational problems. A postjob Virtual Lab simulation showed that the effect of this additional fl uid-residence time was a small increase in silica precipitation that would have minimal effect on productivity.
19. Ziauddin et al, reference 12.
20. Relative permeability effects also can cause decreased oil production with increased water production. It is the combination of this effect and the pump-in tests that support a conclusion of nes migration.
21. A chelating agent stabilizes metal compounds, preventing them from precipitating.
22. An organic mud acid uses formic acid in place of HCl, so a 9/1 organic mud acid is 9% formic acid and 1% HF.
23. Torres C, Ziauddin M, Suntonbura N, Xiao J and Tibbles R:
“ Application of a Unique Clay Stabilizing Acid in the Gulf of Thailand,” presented at the PetroMin Deepwater Technology Conference, Kuala Lumpur, Malaysia, July 14– 17, 2003.
24. Torres et al, reference 23. 0 0 0.5 1.0 Radius, m
> Model results for amorphous silica. The originally planned treatment using organic mud acid produced less than 0.5% of amorphous silica, as a percentage of the formation volume, in the critical volume of the matrix near the wellbore (green). Operational dif culties forced a delay in the owback stage, so the model was rerun using the actual times. The silica deposited with this additional soak time was still small (blue).
1.5 2.0
The complete treatment increased oil pro- duction to 3,000 B/D [480 m3/d], 15 times the pretreatment production rate. The water cut increased slightly to 45%. After three months of production, the well produced oil steadily at 1,500 B/D [240 m3/d].
The productivity increase was better than that predicted by the geochemical simulation. The model had assumed that the main cause of damage was fines migration, but it is possible that the dominant damage came instead from CaCO3 scale or residual drilling and completion fluids. Real-time bottomhole-pressure readings and an analysis of the fl owback fl uids were not available. Had they been, the Virtual Lab simula- tor could have estimated the contributions of the various damage mechanisms, improving future jobs in the fi eld.
further
Sensitive Clays in the Gulf of Thailand Several fi elds operated by ChevronTexaco in the Gulf of Thailand have similar lithologies. The productive sandstone formations have HCl-sensi- tive clays in proportions greater than 15%, and the reservoir temperature exceeds 250° F [120° C]. The formation also contains carbonate minerals.23
The primary damage mechanisms are
swelling of smectite and other clays and migra- tion of clays such as kaolinite-illite and
illite-smectite mixtures. These clays can either line or fi ll pore spaces.
Conventional matrix acidizing— using mud- acid and ClayACID treatments— was ineffective in restoring well productivity in this area.24
In
April 2002, Schlumberger used a new clay- stabilizing acid in this fi eld, a ClayACID formula- tion using an organic acid in place of the HCl. The clay-stabilizing acid is designed to permanently stabilize a formation containing high percentages of silt and clay, while minimizing secondary and tertiary reactions. The treatment deposits a layer of borosilicate glass that immobilizes the clays. The formulation was successful in four of six treatments, and the production increase was stable for at least six months after treatment. Nevertheless, a posttreatment analysis indicated that a better methodology for selecting candidate wells could yield improved results.
The second stimulation campaign, carried out in 2003, used the Virtual Lab software for prestimulation analysis to improve results. The geochemical model inputs included a mineral composition of 9% carbonate minerals, 18% clay— illite, mixed illite and smectite, kaolinite and chlorite— and 6% feldspar. The large propor- tions of these minerals, in conjunction with the high reservoir temperature, make treatment design diffi cult.
1.0 Critical matrix
Treatment with shut-in Treatment without shut-in
0.5
Spring 2004
67
Silica volume, % Wellbore
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