Abstract
Formation pressure plays as an important factor in any stage of E&P business. For drilling operations, formation pressure is a key factor controlling the well design as it can cause several drilling difficulties and direct impact to the well costs. Seismic technology up to date can help predicting the pore pressure zone more accurately. However, to narrow down the range of uncertainty, it is necessary to integrate subsurface geology such as basin evolution, depositional environment, facies distribution, well to well correlation etc.
In general, the pore pressure distribution of Bongkot concession is increasing basinward to southeast. In Greater Bongkot South (GBS), the over pressure is generally found throughout the area as most part of the GBS is located near to the basin center. Relatively lower pressure can be recorded along the active margin, in the Western Terrace trend, the western part of the GBS.
In vertical profile, the hydrostatic pressure in the GBS area, especially in the Western Terrace trend, can be found from mudline to lower unit 2D which is inline with more channel sand prone formation. The formation pressure is getting higher at near top unit 2C where the channel sand intervals are getting thinner with more bar sands intercalated. The formation pressure is peak at lower 2C and 2A and turning back to hydrostatic pressure at near top FM1. The maximum formation pressure in GBS is getting higher from NW to SE, i.e. 1.30 SG.EMW in NW area of GBS and laterally change to 1.90 SG.EMW in the eastern part in the Ton Koon-Ton Nok Yoong area where the basin depocenter is located. Drilling operations is become more challenging in GBS area as the well can encounter both gain and loss.
The regional pressure profile in GBS can be predicted using geophysical methods integrated with nearby well pressure data. However, in detail scale, there is high variation of pressure profile with several steps of pressure increasing at near top 2C. Ramping up shapes in the Western Terrace trend may have some relationship with formation interfingering and pinch out to the west where the paleo high is located. Faultseal and juxtaposition can be another factor of pressure released. Lateral facies change and fault conduit may release the pressure from abnormal high and leave the relative low pressure sands among the other high pore pressure zones.
The highly accurate prediction of formation pressure currently is still beyond the current tool and technology. Therefore back to basic knowledge of geology, well to well correlation, facies variation, juxtaposition, structural control plus the other related geological factors seems to be the best prediction method.
Combination of geological interpretation and drilling technique can help to drill successfully in high variation of pressure profile in GBS area. Understanding of subsurface condition in each particular area and subsurface interval can support preparation and optimization in drilling executing phase. Integrated drilling technique by minimizing the differential pressure seems to be the key success to drill in the high pressure variation area. Controlling rheology and mud properties to minimize loss circulation, slowing down the pump rate as well as integrating the other drilling technology shall be conducted. This integration of subsurface prediction and drilling best practice will lead to successfully drill the overpressure zone with minimum well cost.
