First EAGE Workshop on Pore Pressure Prediction

Over-pressure is one of the important drilling hazards seen globally. Estimates of over-pressured zones/locations and over-pressure magnitudes have a direct impact on well drilling and completion. Overburden gradient (OBG), Pore pressure (PP) and Fracture Gradient (FG) are the three basic outputs of any pore pressure analysis. OBG is calculated from density (RHOB) log data. As density log data does not start from surface/seabed, we use several equations to compute shallow section pseudo-RHOB and integrate it with LWD/wireline RHOB log data. This article discusses the issues with various ways to fill the data gap of shallow section density. PP is normally predicted against shale zones and then calibrated with the most reliable and direct pressure measurements against sands and log data from adjoining shales. This paper also addresses the various issues faced while picking shale points to predict pore pressure.

Pore pressure profiles in Carbonate formations in the North Sea are subject to detailed study, however, there exists large uncertainty on the pressure transient in low porosity and low mobility Carbonates. In the past, the compaction and non-compaction based approaches have been used to resolve the pore pressure but high uncertainty over the results still remains, especially in the more tight zones due to a lack of trustworthy calibration data. In this paper the authors demonstrate that with the help of evolving formation testing technology, it is now possible to accurately measure formation pressures in extremely low mobility carbonates. It requires efficient collaboration between the operator and technology partner to come up with focused solutions which are wellbore centric. The example presented here specifically discusses a North Sea field challenge.

Pore pressure prediction plays a very important role in well planning as exploration targets are shifting to deeper overpressured reservoirs. Pressure related problems in such zones are mainly associated with narrow operating windows resulting in severe well control incidents, sometimes even leading to early abandonment. Uncertainties in prediction models arise from input data, assumptions used in the workflow, and the complexity of the geological and structural conditions. It is important to analyse these uncertainties and develop an understanding of their sources prior to drilling so that various plans and mitigation systems can be put in place.

Pressure prediction methods are based on assumptions about the processes that cause the overpressure and their relationship to rock properties. This study examines the causes of overpressure in the Jurassic and Triassic reservoirs of the Central North Sea. These reservoirs can have overpressures approaching the fracture gradient. The age, temperature, rock properties and proximity to mature source rocks implies that multiple pressure generation mechanisms have contributed to the pressures. Two methods are used to assess the amount of overpressure generated by disequilibrium compaction and also by “Late” geopressure mechanisms. The two methods give similar results and indicate that on the cooler flanks of the basin most overpressure can be attributed to disequilibrium compaction. However, in the deep Graben in excess of 70 % of the overpressure is generated by other mechanisms. These results are consistent with expectations for the geological environment. The fact that most over pressure in the deep basin is not produced by disequilibrium compaction has implications for choice of prediction method and interpretation of rock properties in terms of stress and overpressure.

This paper discusses the influence of hydraulic continuity of reservoirs and faults and the lack thereof on the occurrence of local pore fluid pressure conditions deviating from previously established regional trends. The hydrodynamic- based approaches will be illustrated with case studies from the Netherlands, in particular.

Geopressure modelling and wellbore stability analysis are of upmost concern, and a key task when designing exploration wells in the Saudi Arabian Red Sea region. Initial modelling is based on seismic, offset wells logs, drilling parameters, lithological distribution and geological history in the area. This paper presents case studies from two wells drilled in Red Sea region, where formation pressures encountered ranged from 75pcf to 140pcf. In the first example, while drilling 16” with 78 pcf mud weight, a kick was taken at 6500ft. Based on cuttings the lithology was reported as 100% halite. During well control operations, a sample was collected and described as 100% shale. Formation pressure was calculated to be 94 pcf, so the well was controlled with 104 pcf. In the second case, a water influx was encountered at base salt which is currently reported as the most intense kick in the area. These events required re-calibration of mud weight calculations and new equations to be applied that take into account the creep of halite in response to temperature. In addition, extreme overpressure and fracture gradients encountered within shale inclusion in salt required a real-time re-assessment of the casing design and casing shoe integrity.

Role of geomechanics in influencing efficient drilling practices is not a new observation in the industry. However, the current petroleum economic situation is demanding even more efficiency in order to save well operations from non-productive time (NPT). Therefore, any non-standard solution that can provide guidance to drill wells efficiently has a strong business value for cost effective well delivery, in addition to HSE compliance. While under-compaction driven normal compaction trends of petrophysical/seismic data offers quantifiable estimates of pore-pressure and fracture gradient, this methodology does not support in any geological setting. Thus, need to find alternative indicators is gaining importance to improve predictability of wellbore behaviour during well planning stage. Complexity of geological setting can sometimes increase the complexity of geomechanical/pressure settings like: HPHT, highly stressed, fractured reservoirs, etc. As no standard methodology exist to predict the pore-pressure and fracture gradient in tectonically active/uplifted and carbonate sedimentary sequences, a holistic methodology was considered to constrain the present day stress/geomechanical setting in which pore-pressure and frac gradients are components. In this way, manifestation of the pore pressure and fracture gradient at diverse geological environments were correlated with diversity in drilling environments. This paper has been explained with few non-standard observations in 3 case studies from different geological and geomechanical settings. Each case offered different lesson as well as challenge.

Seismic low velocity anomalies may indicate overpressure when related to porosity anomalies due to undercompaction. However, other processes can generate overpressure without porosity anomalies such as lateral transfer. Geological pore pressure modeling can help to explain such situations. Examples will be shown with anomalously low velocities in anticlinal settings not observed in surrounding synclines.

The standard real-time pore pressure modeling workflow contains several steps of human interaction, e.g. drawing and adjusting shale and normal compaction trend lines, and also manual picking of a final pore pressure curve. This introduces a subjective component to the modelling procedure and the result will very likely depend on the skills and experience of the analyst. In the frame of a case study, we present how automation of the pore pressure modelling workflow can be approached to support the real-time analysts. The results from the algorithms are compared with a standard pore pressure analysis. This can be important in a real-time analysis when a project is shared by several analysts who work on shifts or when several experts share the analysis (such as in remote operations). In this context, automation does not necessarily stand for a fully autonomous system in which the user plays no or only a supportive role. Automation of single functions or part of the workflow shall support the analyst, who is still requested to confirm or reject proposed information and solutions.