STEVE O’CONNOR**, JEROME ASEDEGBEGA**, GUY MARKHAM**, CHRIS WARD**, BITRUS PINDAR**, NANCY UMOREN**, ADEDAYO ADEBAYO*, KINGSLEY NWANKWOAGU*, OLUSOLA SCOTT-OGUNKOYA** AND GBENGA LUFADEJU***
Fracture gradient forms an essential parameter in the pre-design stage of drilling operations, reservoir exploitation and stimulation. Several fracture gradient algorithms are available in literature, however many are empirical and based on data from the Gulf of Mexico, where shales have been demonstrated to be very different to those from other parts of the world. These relationships can be adapted for the Niger Delta; however it can be difficult to estimate stress ratios (K) and Poisson’s ratios (PR) unless the requisite data to do so exists.
This paper uses a different approach, linked to rock properties that determine K and PR, but not by specifically determining these parameters individually, instead using regional data-set of Leak-Off data (LOT’s) from the Onshore Niger Delta. Models are built for shales and sands/silts, thus accounting for the varying lithology in the region.
The data-set used in the study contains data from over 100 wells, and fracture gradient measurements taken in the four depositional belts in the Onshore. One of the most noticeable observations is that the LOT’s are at higher pressure for the same depth in older depo-belts. This links back to pore pressure and overburden weight. The results obtained from the developed models establish a novel simple mechanism for fracture gradient prediction that is based on readily obtainable parameters.
The resulting model will give more accurate definition of the drilling window and thus improved well design. This will be critical as exploration achieves deeper drilling depths onshore and true HP/HT conditions.
* Sonar/Tusk, Lagos **Ikon Geopressure, UK and Lagos ***DPR