Peter Olden

Modeling combined fluid and stress change effects in the seismic response of a producing hydrocarbon reservoir

Editors note: A fuller version of this article can be downloaded in pdf format from the GUMPA project Web site at the following URL - http://www.pet.hw.ac.uk/research/gumpa/index.html The exploration and production of hydrocarbons are generally accomplished with the aid of 3-D seismic to image reservoir structure and, in some instances, reservoir properties and direct hydrocarbon indicators. Repeated seismic surveys over a period are termed time-lapse seismic (and sometimes 4-D seismic ). Changes observed in the seismic character with time have been attributed to impedance changes as a result of production (e.g. Gawith and Gutteridge, 1996). These changes have been used in a few producing fields to monitor reservoir performance. Identifying observed differences in repeat 3-D surveys and relating these to either in-situ saturation or stress-state changes, or both, has been difficult because of the lack of control data. It has been noted that in some fields (Watts et al., 1995), the sensitivity to stress changes can be very much greater than the sensitivity to saturation changes. In other fields (Landro et al., 1999), the saturation changes are thought to be more significant. To aid understanding, a need for greater integration of geophysics and reservoir engineering has been noted and was the motivation for this study (Jack, 2001). There is a limited window of opportunity in a fields producing life when there are sufficient changes (saturation or stress) in the subsurface to show a surface seismic response. These changes have to be monitored before the field has reached significant decline for the observed changes to be exploited for reservoir management (through in-fill drilling for by-passed, compartmentalized or attic oil). Reservoir modeling is an essential tool for managing the development of and production from hydrocarbon reservoirs. Many technical issues however surround the realism and validity of the models on which management decisions are based. …

Geomechanical modelling of CO2 geological storage with the use of site specific rock mechanics laboratory data

Many diverse challenges – political, economic, legal and technical – face the continued development and deployment of geological storage of anthropogenic CO2. Among the technical challenges will be the satisfactory proof of storage site security and efficacy. Evidence from many past geotechnical projects has shown the investigations and analyses that are required to demonstrate safe and satisfactory performance will be site specific. This will hold for the geomechanical assessment of saline aquifer storage site integrity where, compared to depleted hydrocarbon fields, there will be no previous pressure response history or rock property characterization data available. The work presented was carried out as part of a project investigating the improvement in levels of confidence in all aspects of saline aquifer site selection and characterization that could be expected with increasing data availability and in-depth analysis. Attention focused on the geomechanical modelling and the rock mechanics data used to populate models of two storage sites in geological settings analogous to those where CO2 storage might be considered. Coupled geomechanical models were developed from reservoir simulation models initially incorporating generic rock mechanical properties and then laboratory-derived site-specific properties. The models were run in various configurations to investigate the effect of changing the rock mechanical properties on the geomechanical response of the storage systems. Modelling results showed that the pressure response at one site due to low injectivity caused significant potential for fault reactivation. Increasing the number of injection wells, thereby reducing the individual rates needed to deliver the target capacity, reduced the injection pressures and ameliorated, but did not eliminate, this adverse response.

Coupled Modelling of CO2 Injection into a Realistic North Sea Aquifer

The work describes the use of coupled reservoir simulation geomechanical modelling to investigate the potential for geomechanical failure within a saline aquifer subjected to CO2 injection for geological storage. The model was based on a realistic North Sea (Forties Sandstone) formation. The work was carried out as part of the UK Storage Appraisal Project and was mainly concerned with issues of injection pressure, injectivity and thereby storage capacity. The default criterion within the project was to consider a maximum injection pressure based on (hydraulic) fracture pressure gradient. The geomechanical modelling work was carried out to see if there was any scope to change this based on other potential modes of geomechanical failure. The results show that for the scenarios modelled, geomechanical failure is unlikely in the formation providing the injection rate is controlled so that the injection pressure does not exceed the fracture pressure at the well.

Rock mechanics factors in enhanced fluid flow simulation

A stress-sensitive fluid flow simulator which requires minimum manual intervention has been constructed by minimum manual intervention has been constructed by coupling a fluid flow with a rock-mechanical modelling program.