Stress Evolution Of Maari Field, Nz: Implications For Fault/Fracture Integrity, Stress Prediction, Infill Drilling And Borehole Integrity

Abstract

Maari Field, offshore Taranaki Basin, NZ, is an oil field producing via horizontal wells from Miocene deep water turbidites of the Moki Fm. Maari has produced more than 35 MMSTB since initial development in 2009. A 2014-2015 infill drilling program encountered greater than anticipated reservoir pressure depletion and more challenging mud losses while drilling than during initial field development. Currently, an additional infill drilling option is being evaluated and in order to reduce risk of repeating previous drilling challenges, geomechanics studies are being conducted to characterize the evolving stress-state of the field and to better understand root causes of past drilling difficulties. Ultimately, the objective of the current analysis is to make recommendations that should reduce risk for future infill drilling.

Recent secondary recovery water injection step rate tests have proven to be particularly useful in characterizing the time & pressure dependent stress state of Maari Field. Although Maari Field was initially developed with three inclined water injection wells, these ultimately failed to maintain reservoir pressure in the field which had become variably depleted by more than 1000psi from initial hydrostatic conditions. The question of where all the original injected water went is a separate geomechanics conundrum beyond the scope of this discussion, however, because the original injection strategy was to maximize volume injected, it is possible that stability of nearby faults or fractures could have been compromised. Essentially, such faults and fractures could have become thief zones for the injected water in a manner similar to drilling mud losses from perturbing intersected faults and fractures. The original three injectors were abandoned and sidetracked to become infill oil producers in 2014. Also in 2014, a watered out horizontal production well on the west flank of the field was converted for use as a flank water injector and has been successful thus far at starting to restore reservoir pressure to at least one nearby production well. Water injection in this well is designed to be conducted carefully at matrix conditions in order to initiate a flank water front that moves through the reservoir sands rather than fractures or faults. Injection pressure strategy is determined by step rate injection tests conducted at different points in time since 2014 and at different ambient reservoir pressures. These tests have been used to define the stress path of minimum horizontal stress evolution with pore pressure changes in Maari Field caused by ongoing oil production and water injection.

Understanding stress path evolution also helps decide which fault orientations could be most problematic through the life of the field. For original hydrostatic conditions at Maari, vertical stress (Sv) is about the same magnitude as the maximum horizontal stress (SHmax) and both are greater than the minimum horizontal stress (Shmin). This defines a transitional stress regime comprised of both normal and strike-slip faults. 3D seismic data corroborates this, confirming two recently active fault sets, one normal and one strike-slip. During Maari stress evolution, Sv will likely remain constant. Both SHmax and Shmin will diminish during depletion and increase with sufficient water injection (at least locally). For the depletion scenario, a normal faulting stress state prevails; relative stress magnitudes are Sv > SHmax > Shmin. For localized increases in pore pressure above hydrostatic due to water injection, the stress state returns to the original transitional state or possibly a strike-slip stress regime prevails with relative stress magnitudes; SHmax > Sv > Shmin.

By characterizing the production/injection stress evolution of Maari Field through step rate injection testing, we were able to quantify the absolute magnitudes of the horizontal principal stresses, which provided new information to quantify the natural fracture gradient to avoid pressures that could destabilize faults and fractures while drilling through variably depleted reservoir compartments. For instance, step-rate injection operations at initial, depleted, and injection-charged conditions have documented a non-linear stress path that has become a predictive tool for quantifying Shmin and SHmax stress magnitudes. It appears that at depletion conditions, the faults are likely to be relatively stable. However, during injection operations, the stress state is such that active normal faulting and strike-slip faulting can be supported because injection pressures produces a critical stress state transitional between active normal faulting and active strikes-slip faulting. The implications of this stress-pressure evolution may likely impact drilling and reservoir modeling.

AAPG Datapages/Search and Discovery Article #90324 © 2018 AAPG Asia Pacific Region GTW, Pore Pressure & Geomechanics: From Exploration to Abandonment, Perth, Australia, June 6-7, 2018