T: +44 191 334 2191 E: info@ikonscience.com W: www.ikonscience.com Pore Pressure Prediction in the Niger Delta NAPE 2011 Lagos, Nigeria 28 November-2 December 2011 Extended Abstract PORE PRESSURE PREDICTION IN THE NIGER DELTA LESSONS LEARNT FROM REGIONAL ANALYSIS. Stephen O Connor*, Richard Swarbrick*, Bitrus Pindar*, Olidapo Lucas**, Folake Adesanya**, Adebayo Adedayo**, Kingsley Nwankwoagu**, Alexander Edwards*, Jakob Heller* and Patricia Kelly*. *Ikon GeoPressure 1, Durham, UK. **Sonar Limited, Ikeja, Nigeria. ABSTRACT Accurate pore pressure prediction is vital for successful and safe drilling of wells, and the Deep- and Ultra-Deep offshore area of the Niger Delta is no exception. Kicks have been taken, for instance, in permeable zones within the Early Miocene shales, suggesting mud-weights have been set too low as a result of inaccurate pre-drill pressure prediction. As part of the Niger Delta Pressure Study, two typical pore pressure profiles were observed in the Deep- and Ultra-Deep offshore area. The first occurs in shale-rich regions (low net/gross, with isolated (i.e. un-drained ) reservoirs, where sediment loading is high, top of overpressure is shallow, and overburden-parallel trends of pore pressure with depth are observed (Figure 1). Here standard shale-based techniques such as Eaton (1975) and Equivalent Depth can be used to interpret pore pressure in shales, and by implication, any encased sands. A single normal compaction curve developed for the Deep and Ultra-Deep offshore area can be used (with wireline log - sonic, resisitivity and density and/or seismic velocity data) to predict these shale pressures accurately to current drilling depths in the Deep and Ultra-Deep offshore, since analysis of overpressure generation mechanisms as part of the regional study reveals only disequilibrium compaction as an active mechanism (plus hydrocarbon buoyancy effects/lateral transfer effects, the latter typically at the crests of relatively shallow anticlinal structures see sands in Late Miocene; Figure 1). The lack of evidence for secondary mechanisms of overpressure generation (to present drilling depths) legitimises using under-compaction relationships such as Eaton (1975) to interpret shale pressures. The second typical style of profile is found in sand and silt-rich regions, where top of overpressure tends to be deeper, followed at depth by a sharp pressure transition zone (Figure 2). These previously mentioned techniques can also be applied to interpret these deep shale pressures in this situation, however, they cannot be used to infer pore pressures in the sand-rich horizons above as the porosity/ effective stress relationship developed in low permeability shales and detected remotely by Eaton (1975) and other under-compaction models can be affected, by processes such as cementation and pressure dissipation (or lateral drainage). The pressure in these sands, however, can be measured directly by taking pressure tests. Using these relationships and measurements therefore allows interpretation of shale pressures throughout the Deep- and Ultra-Deep offshore area and comparison with sand pressures. In many cases, shales have substantially higher pressures than sands. 1 Ikon GeoPressure is the trading name of GeoPressure Technology Ltd
Figure 1 Profile A : Shale-rich lithology where reservoirs and shales are in pressure equilibrium. Red (resisitivity), brown (density) and blue (sonic) shale pressure interpretation. Red triangles are sand pressure tests, pink squares are leak-off test results, estimating fracture strength of rock. Figure 2 Profile B : High net/gross. Using methodology outlined in Figure 3, prediction of the shale pressures (and hence avoidance of kicks) was possible pre-drill assuming ages of seismic markers were known (see text for explanation). Red circle is the Fluid Retention Depth or FRD.are leak-off test results, estimating fracture strength of rock.
In this paper, we describe another method to calculate these shale pressures, one based on sedimentation rates and loading. The top of overpressure is the point at which the pore pressure starts to deviate from the hydrostatic line. In terms of process, as fluids are inhibited from escaping as sedimentation increases, porosity loss is slowed, and overpressure builds there is a departure from the normal compaction curve. The depth of top of overpressure is controlled by the permeability, rock compressibility and sedimentation rate. The Fluid Retention Depth (or FRD) is the point at which rocks completely cease to dewater due to low sediment permeability (Swarbrick et al., 2002; Gluyas and Swarbrick, 2004). The FRD is determined by an extrapolation from inferred shale pressures, to intersect the hydrostatic gradient the trend should be approximately overburden parallel. Swarbrick et al. (2002) showed that there is a correlation between sedimentation rate and FRD using data from shale dominated regions (Figures 3 and 4). Data in Swarbrick et al. (2002) is presented from the Gulf of Mexico, Trinidad, Nile Delta and other world-wide basins. Using this trend for pore pressure allows an assessment of shale pressures to be made. This technique is highlighted below. Figure 3 Methodology for prediction of shale pressure using Swarbrick et al. (2002) applied to data from Nile Delta. Using data from Mann and Mackenzie (1990) from the Nile Delta, where sedimentation or depositional rate is calculated to be 810m/Ma, using the relationship in Swarbrick et al. (2002) suggests an FRD of 2,620 feet TVDbml (where bml is below mud-line or seabed). Therefore, with foreknowledge of sedimentation rate, one can estimate the FRD depth using data compiled by Swarbrick et al. (2002). With this in mind the pressure at any depth can be estimated on a Pressure-Depth plot by plotting a gradient parallel to the overburden gradient, starting at the FRD. This method assumes that overpressure is generated entirely by disequilibrium compaction which for the Niger Delta seems reasonable since the sediments are young, shale/sand dominated and the velocity-density cross-plots reveal little or no secondary mechanisms to be present. In Figure 2, we present the results of testing this approach on a well taken from the East of the study area where water depth is 2433 feet. In this well, the Late Miocene, although relatively shale-rich, has numerous sand units present. Pressure tests in these sand record minor overpressures, with pressures
affected by hydrocarbon buoyancy effects. Hydrocarbons are suggested both by fluids gradients from the pressure tests and by resistivity log response. Shales in-between the sand units are interpreted using the under-compaction techniques mentioned previously, to have pressures above those in the reservoirs, a common feature of the Deep- and Ultra-Deep offshore. These sands are laterally-drained and allow horizontal pressure escape to shallower levels in the Delta and/or seabed. Supportive evidence for this lateral drainage is seen where comparing pressures in the two deepest sands in the well i.e. the deepest sand has pressure test data that records lower overpressures than the sand above, at shallower stratigraphic intervals, implying differential drainage of pressures. Towards the base of the Late Miocene, sand units are rare, and, as shale-lithology dominate, pressures increase, recorded by increases in mudweight. Several kicks are reported in this well at this level, taken in thin sand units, therefore suggesting this increasing shale pressure were not predicted pre-drill. Using the pressure tests at a depth of 9850 feet TVDss (or 7417 feet TVDbml) and an age of this sand unit as approximately the Top Middle Miocene of 11.6 Ma, and the relationship displayed in Figure 4, predicts the FRD for this sedimentation rate of 638 feet (or 194m) per Ma in this well to be 0.9 km or 2950 feet TVDbml (or 5400 TVDss). The shale pressures at depth, using the implied pore pressure trend for shales, gives a close matches to the kick data close to the base of the Late Miocene interval i.e. using this method alone would have successfully predicted the shale pressures and prevented drilling problems. Figure 4 Sedimentation Rate vs. FRD (Swarbrick et al, 2002). Green arrow represents Nile Delta data (see Figure 3). Blue arrow is data from a Niger Delta well in the study. As part of the Study, we analysed FRD s from 15 selected wells all with well-defined stratigraphy, gamma ray, sonic, resistivity and density logs and pressure data to complete this analysis, all of these criteria need to be fulfilled. The majority of these wells give a close match between extrapolating our shalebased interpretation to intersect the hydrostatic line, and a calculation of FRD based on sedimentation
rates, the method outlined above. In these wells, FRD s varied between 2750 feet TVDbml and 3850 feet TVDbml. The average calculated FRD for the selected 15 wells from both the West and east regions of the Delta is 3270 feet TVDbml. Using this approach defined in Swarbrick et al. (2002) provides a second, independent method to calibrate the log and/or seismic velocity based techniques of Eaton (1975) and other algorithms to interpret shale pressures in the deep- and Ultra-deep offshore of the Niger Delta. This method to estimate the shale pressures, and hence magnitude of overpressure, based on sedimentation rate is linked to process (disequilibrium compaction) although is empirical. In a pre-drill situation, seismic chrono-stratigraphic markers can be used to establish the rate of sedimentation, with seismic facies used to provide a guide to net/gross. Comparison of this method with analysis of shale-based pressure profiles using the full suite of available wireline log responses provides added confidence in the regional pressure prediction. Furthermore the comparison improves our ability to define the regional flow characteristics of the main reservoirs which govern migration and trapping of hydrocarbons. Acknowledgements The authors would like to thank the Nigerian Department of Petroleum Resources (DPR), in particular Lufadeju Olugbenga, National Data Repository (NDR) and NAPIMS for their active support of the study and their assistance in providing data. The authors are also very appreciative of the assistance provided by representatives from the sponsor companies (SNEPCO, Addax Petroleum, Chevron Nigeria, Petrobras Nigeria, TOTAL Nigeria and ENI/AGIP). The management of Sonar Limited is also acknowledged. The statements made in this extended abstract represents the views expressed by the authors and not necessarily the views held by those organisations listed above. OPTIMISE SUCCESS THROUGH SCIENCE Registered in England No.03359723