Calcium carbonate scale was detected in the majority of wet producers in a tight carbonate reservoir in the northern part of Saudi Arabia. Extensive lab work indicated that a phosphonate-type scale inhibitor was effective in mitigating carbonate scale, as well as sulfate scale that were found in a few wells. Field application of conventional scale squeeze treatment in this field is not an easy task for the following reasons:
The formation is tight and water blockage is a serious concern.
Formation brine contains high Ca concentrations (up to 19,930 mg/L).
The formation contains high TDS (up to 231,262 mg/L); therefore measuring low concentrations of the phosphonate inhibitor is a real problem.
Nearly 70% of the field is offshore, which imposes limitation on the volume of fluids that can be used.
As a result of these challenges, several modifications were introduced to conventional scale squeeze treatments, where a large amount of aqueous phase is typically introduced into the formation. Coreflood experiments were used to evaluate various available options to reduce the amount of aqueous phase introduced into the formation and associated problems. Based on the results obtained from these tests, significant changes were introduced to the preflush, main treatment, postflush, and soaking time.
The new modifications were applied at two wet producers in this field. Well Z-C is a vertical well with 70 vol% water cut, 218°F bottom hole temperature, and 78,540 mg/L TDS. Well B is a horizontal well with 5 vol% water cut, 235°F bottom hole temperature and 209,828 mg/L TDS. An extensive wellhead-sampling program was conducted to measure residual scale inhibitor in the produced brines.
Both wells responded positively to the treatment. The new modifications have resulted in better well response. Analysis of phosphonate in the wellhead samples was used to determine the MIC for this field.
Field "Z" was discovered in 1964. Oil production from this field is mainly from two carbonate reservoirs: HN and HD. The average thickness of HN and HD reservoirs is approximately 97 and 166 ft, respectively. The average porosity for of the two reservoirs ranges from 16 to 20 vol%, whereas the permeability ranges from 6 to 50 mD for HN reservoir and from 9 to 60 md for the HD reservoir.
Bulk XRD analysis of the HN reservoir cores indicates that the zone of interest contains 97–100 wt% calcite and 0–3 wt% ankerite. On the other hand, HD reservoir cores contain 70–92 wt% calcite, 0–30 wt% dolomite and 0–5 wt% ankerite.
Production from the two reservoirs started in 1970. The field produces Arabian extra light oil (°API ~ 38). The crude oil has significant contents of CO2 (5 mol%) and H2S (3–5 mol%). The reservoir pressures and temperatures are in the range of 3,900–4,200 psig and 210–235°F. More than 70% of the oil producers are off-shore.
Peripheral water injection started on 1974 to maintain reservoir pressure. The injection water (IW) is obtained from 21 water supply wells drilled in a shallow aquifer. The injection water is treated at the injection plant with an oxygen scavenger and a biocide. The water injection plant has high pressure pumps which were designed to provide 1,400 psig pressure. Produced water from this field compliments the waterflood operation using separate disposal wells.
Table 1 gives the chemical analysis of three producers from HN reservoir, three producers from HD reservoir and two water supply wells from HW reservoir. The TDS of the HD reservoir brine varies from 33,400 to 292,000 mg/L. Calcium and sulfate ions are in the range of 2,392 - 39,280 mg/L and 150 to 813 mg/L, respectively. The TDS of the HN reservoir brine varies from 27,000 to 230,000 mg/L. Calcium and sulfate ions were in the range of 1,904 - 18,876 mg/L and 263 - 965 mg/L, respectively.