The Jilh formation (JILH) is a tight, predominantly dolomitic Triassic formation occurring from 8,000 ft true vertical depth (TVD) to 10,000 ft TVD across the Ghawar field in Saudi Arabia. Drillers experienced extremely high pressured saltwater, oil and/or gas flows in about 20% of the wells that traverse it. The highest recorded flow rate from the JILH was 25,000 barrels per day (BPD) of saltwater and the highest mud weight required to control the JILH flow was 164 pounds per cubic foot (pcf) (22 ppg). The majority of the observed flows have been saltwater, which required a mud weight of 120 pcf to 155 pcf (16 ppg to 20.7 ppg) to control the well. This unpredictable nature of the JILH flow has not only mystified the drillers, but also plagued them across the Ghawar field.

If abnormal pressure is encountered in the JILH, a casing string is required to isolate it prior to drilling the Khuff gas reservoirs. If abnormal JILH pressure could be reliably predicted, 80% of the Khuff gas wells could be drilled with a "Slim Hole" casing design resulting in substantial reductions in overall well costs.

This paper presents a recent pilot study for predicting abnormal pressure in the JILH in the central area of the Ghawar field, Saudi Arabia. The 3D pore pressure distribution is estimated using a state-of-the-art integrated 3D pore pressure modeling software (PP3D), which is a combination of basin modeling and data inversion techniques. All available data sets (geological, logs and drilling reports) in the area of interest were used to conduct extensive log analyses.

This study identified the main cause of abnormal pressure in the JILH as fluid migration from the Sudair shale, due to formation compaction during burial. Well developed anhydrite stringers at the bottom of the base Jilh Dolomite (BJDM) blocked fluid migration to the JILH from the Sudair shale. Abnormal pressure exists in areas where these anhydrite layers did not develop well.

The pore pressure along well trajectories of four wells was blind tested with the predicted 3D pore pressure distribution. The average difference in pore pressure for these blind tested wells was −4.5 pcf (−0.6 ppg). Pore pressure in eight additional wells was also blind tested and good agreement between the actual and predicted pressures was found (average difference of −0.75 pcf i.e., −0.1 ppg). It was concluded that the accuracy of the model prediction would be adequate to optimize the drilling plans and casing programs in future wells.

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