|MACHAR: UNLOCKING FURTHER DEVELOPMENT OF A COMPLEX FRACTURED CHALK FIELD|
|Field Developments and Case Studies|
The Machar oil field in the UK Central North Sea is a complex fractured Cretaceous chalk and Palaeocene sandstone oil reservoir, trapped against a steeply dipping salt diapir. The field was discovered in 1976 and has been developed in a phased manner appropriate for the high levels of uncertainty over reservoir distribution and performance. The initial development comprised two extended well test phases of 10 month duration, (1994 and 1995) testing the response of two producers to natural depletion (Phase 1), followed by the addition of a third well to test recovery under water flood (Phase 2). The main phase of production (Phase 3) began in 1998 through five production and two injection wells, through a subsea development tied back to a central processing facility over the Marnock field. Phase 3 was supplemented by an infill phase from 2000 which added four more production wells over the established field with the majority of development and offtake from the west-central core area. Vital pressure support is provided by high rate water injectors, one on the west flank, one at the field’s southern limit and a recently drilled water injector on the eastern flank is due to come online autumn 2010. Although sparsely developed, the northern flank has two producers (figure 1).
Seismic imaging has historically been poor due to a combination of variable, often weak reservoir reflectivity, steep dips, multiples and disruption from shallow gas and channels. Reservoir thickness varies greatly around the field, tending to increase with depth from a near crestal pinchout, to several hundred metres in some downdip areas. The northern area contains a large slump which has been displaced down the flank of the diapir leaving a reservoir absent zone updip. There is evidence of similar slippage to the east, and since this flank is steeper and historically lacked coherent reflectivity, a model of reservoir absence was developed here (figure 1). Despite a programme of fourteen dedicated exploration and appraisal penetrations and three pre-production wells, the steeper eastern flank remained undrilled and historically lacked coherent reflectivity.
A major leap forward on seismic reprocessing in 2007 reduced the subsurface risks associated with this area and a new subsea site reduced the drilling risks and costs sufficiently to allow the Machar East well to be sanctioned. Enhancing the seismic sufficiently to fully assess prospectivity on the east therefore became a priority, and ultimately led to successful drilling on the east in 2008. Drilling the Eastern Flank on Machar was a bold move for BP and successful results from the well in 2008 changed the entire perception of Machar and have acted as a springboard for further development of the field. This included a sidetrack in the northern area of the field in 2009 and a third injection well completed in summer 2010. Additional infill targets have been identified for further development of the field in 2011 and beyond.Figure 1. Machar field map (top Chalk depth map showing well locations. Green – oil producers, blue – water injectors)
|RESERVOIR PERFORMANCE AND MODELLING|
The field has been developed primarily by accessing the prolific fractured chalk reservoir. This allows high productivity wells (several with productivity index >100 stbd/psi); single well rates up to 20-25,000 barrels per day and a field plateau of around 35,000 barrels per day. Since initial pressure was close to bubble point at the crest of the field, pressure support is an important factor in suppressing gas oil ratio and maintaining high oil rates. Thus the high offtake rate was balanced by high rates of water injection. After nearly two years of high rate dry oil production, water cut began to rise dramatically, with individual wells either watering out, or becoming uncompetitive in a water-handling constrained system. Improving the understanding of the fracture pathways which allowed such rapid water movement, and developing an ability to predict fluid and pressure movements within these zones became a priority. Data gathering during reservoir drilling operations (mud losses and Stoneley wave data) confirmed that faults mapped on seismic data tended to correlate with the main zones of open fracturing. Therefore considerable effort was put into explicitly defining seismic faults and incorporating these into the reservoir simulation model. Subsequently, running LWD image logs and FMI logs in the wells on the eastern side of the field has been useful to identify open fractures to optimally locate perforation intervals prior to acid stimulation of these intervals. In addition, significant work has been progressed to understand water injection sweep in the field and the imbibition mechanisms in the fractured Chalk reservoir. This work highlighted that a stable and balanced voidage associated with reasonable offtakes were paramount in reservoir management, resulting in minimal water breakthrough and mild water-cut increase.
The primary (and baseline) Machar 3D seismic survey was acquired in 1989 and despite re-acquisition/ re-processing attempts in 1997 and 2001-3 respectively (4D trial), the limited improvement in data quality did not progress the reservoir imaging sufficiently to either clarify east flank reservoir development or provide the fault definition improvement required to significantly advance understanding of the field dynamics. In 2005 studies were undertaken to establish the potential for further improvement of the seismic including a seismic illumination study, swath trials of pre-stack depth migration with further analysis suggesting probable enhancements in the areas of noise reduction, resolution and multiple attenuation as well as the critical steep dip imaging. Thus a full-field anisotropic Kirchoff pre-stack depth migration was initiated.
Results were dramatic with the new imaging allowing chalk reservoir to be identified on the east as a clear wedge pinching out high on the diapir flank with sufficient continuity to correlate with known reservoir on the adjacent calibrated flanks and with dip integrity for direct correlation with the well defined chalk in the basinal area surrounding the field. A comparison of three seismic vintages over the eastern flank, including the new reprocessing is shown in figure 2 with the reservoir reflectivity to standing out as higher amplitude events. This illustrates the progression from the early post-stack migration, with no coherent reflectivity in the target area (figure 2a), to an improved pre-stack time migration, showing ill-defined, low frequency reflectivity (figure 2b). The final pre-stack depth migration (figure 2c) has identifiable top and base chalk reflectors.
Full-field, there is a more accurate structural definition with improved well-ties, enhanced fault resolution and a new picture of reservoir distribution and communication. Some key reservoir performance observations are better understood and in particular reservoir is mapped over some of the crest of the field suggesting a communication route between key segments which were historically considered separate. Top chalk reservoir maps associated with the main seismic processing vintages are shown in figure 3.
Interpretation of the reprocessed seismic has allowed extensive reservoir to be mapped concentrically around the full extent of the diapir. The new interpretation resulted in an east flank originally in-place oil volume of over 90 million barrels. Furthermore, the new extension of reservoir mapping up-dip, suggests improved reservoir properties as these are related to height on the structure. The increased areal extent of reservoir enabled the planning of a well of sufficient length for an effective chalk producer, with considerable exposure to a potentially highly fractured reservoir.
A full-field reservoir model was constructed to analyse the nature of fluid and pressure movements through the prospect area. Critical to the effectiveness of this model was the characterisation of fracture permeability. A dual porosity model of the chalk fracture - matrix system was employed with the seismically identifiable faults incorporated as discrete mapped objects within the grid. From test data isotropic fracture permeability was defined based on depth dependency, ranging from ~3000 mD near the crest to ~50 mD close the oil water contact. In addition to the larger scale fracture zones, interpretation of mud-loss and Stoneley wave data identified a higher density of lower permeability (<40 mD) fractures with a typical 10-15m spacing. This background fracturing was characterised via flow pseudos based on a number of mechanistically modelled fracture styles. Although the east flank prospect lies between a prolific water injector to the south and a producer to the north, it was initially thought that the considerable distance between the wells and the pressure sink of production wells in the western area, would make significant water influx to the east flank, unlikely. However as shown in figure 4, base-case modelling predicted a matrix water front approximately 1 km from the injector around the eastern flank, and a fracture water front that extended into and beyond potential drilling targets.
On the basis of the modelling output, the proposed well was moved further north, away from the water source and an assumption of water presence at the drilling location was built into the profile and reserves estimate. The well was angled with the toe towards the water injector which, on the assumption that water would advance as modelled from down-dip, would facilitate avoidance of water, both on initial completion and on potential future water shut-off interventions.
The Machar East well was drilled from a new subsea site, 1.4km away from the subsea site A, between July and October 2008 and encountered a full reservoir section both in the Palaeocene (Maureen sands and Ekofisk chalk and sands) and in the Cretaceous chalk with a highly fractured Tor formation. Reservoir depths and thicknesses were within the predicted range, with the seismically less well defined Maureen sand section at the high end of predicted thickness. Water-imbibed matrix zones were encountered in the latter part of the well, suggesting that the modelled matrix water front (figure 4) under-estimated matrix sweep to the east. Despite this, the well is expected to access reserves within the predicted range. 375 m MD of dry oil-bearing reservoir were penetrated in the Maureen, Ekofisk and Tor reservoirs, including 310 m MD in the primary fractured Tor target. Careful monitoring of mud-loss data, acquisition of image logs (while drilling and on wireline) and array sonic for Stoneley wave data, provided the basis for intervals selected for perforation and acid stimulation. A reasonable correlation between seismically predicted faults and fracture zones identified through drilling and logging was observed, supporting the effectiveness of the reprocessed seismic in locating the well with respect to the critical fracturing. A facility restricted clean-up of the well, confirmed a dry oil rate which peaked at 6,000 barrels per day. The well is now tied back subsea to the ETAP central processing facility.
Following on from the success of the Machar East producer, two additional wells have been drilled; a sidetrack in the northern slump area was drilled in 2009 and the use of a new completion technique in the well has resulted in a substantially higher productivity index than predicted; on the eastern flank of the field, a water injector well was drilled and completed in summer 2010. The eastern flank injector well encountered a slightly thinner than prognosed Palaeocene section, a steeper than predicted, highly fractured Ekofisk section and penetrated 279m of Tor at the required vertical depth range for the main injection target. Drilling a 763m long 8 ½” reservoir hole section was achieved in a single run using real-time imaging of structural dip and fractures with clear and concise steering instructions, without resorting to a sidetrack contingency despite the evident large depth, dip and fault position uncertainty. A significant mud-loss interval was dealt with, which could have led to early well TD in other circumstances, enabling the drilling of an appraisal toe to examine hydrocarbon presence below the proven field OWC. Image logs and mudloss data were essential for locating the perforation intervals in the well and data gathering will assist with the interpretation of imbibed zones and saturations within the well, allowing interpretation of the fluid movement in this part of the field and optimisation of future well targets on the eastern flank. At the time of writing, this well is awaiting subsea tie-in.
The future development of Machar looks promising with the potential to extend water-flood phase of the field development, opportunities exist to continue investing in seismic studies, dual lateral technology is being considered for infill wells along with assessment of the optimal completion strategy for the next phase of production wells. Multiple well targets are in the planning cycle for drilling in 2011 and beyond.
I would like to thank BP for the opportunity to give this presentation and my colleagues in the ETAP team (Chris Pearse, Yann Jehanno, Marie O'Hanlon) and the wider team (Dave Richards, Adrian Zett and Dawn Houliston) for their support.