Print this pageAAPG ANNUAL CONFERENCE AND EXHIBITION
Making the Next Giant Leap in Geosciences
April 10-13, 2011, Houston, Texas, USA
Reducing Uncertainty in a Basin-Centred Gas System; Designing an Intense Data Collection Program
(1) Onshore Gas, Shell Canada Ltd, Calgary, AB, Canada.
Shell Canada’s Deep Basin asset is a stacked series of Cretaceous age tight clastic reservoirs in a basin centred gas system in West Central Alberta, Canada. Each reservoir has distinctly different geological and petrophysical properties, which complicates the development program. The majority of the wells were drilled before Shell acquired the asset and generally nothing beyond a basic suite of logs had been collected. The unpredictability of producing intervals (both rate and what actually produces) has lead to design and implementation of an intensive data collection program.
The program has three parts; detailed core analyses paired with advanced log programs, outcrop based studies and development pilots. The first two will be discussed in detail in this presentation. Core collection targeted strata with high GIIP but lower URG and poor state of knowledge. Core collection was paired with mud gas isotope data, advanced logs (NMR, ECS) and Sensaline production logging to reinforce data sets. Special core analyses included geomechanical, fluid sensitivity, low k poro-perm, commutation, coal maceral, TOC-Rockeval and chemostratigraphy. Intensive data collection also occurred in outcrop studies in Grande Cache, not far from the Deep Basin producing areas. The exposed strata have provided important information on depositional setting, reservoir architecture and mineralogy in a cost effective manner for a basin where subsurface data is missing or sparse. Multidisciplinary field courses have been developed in order to improve cross-discipline dialogue on frac optimization, thin bed pay evaluation, reservoir connectivity and other topics. An XRD study (spanning core and outcrop) in conjunction with other data will be used to discuss how mineralogical variations between the formations impacts log evaluation, completion approaches and the field development plan.
Low porosity systems present unique problems that can greatly increase uncertainty. Minor changes in lithology (and hence grain density) can easily hide porosity. Generally only water of condensation is produced, which means no easy way to quantify the salinity of formation waters. This uncertainty, in combination with a poor characterization of formation clay has resulted in formations appearing far wetter than they actually are. Through careful data collection and analysis a much more accurate petrophysical model has been created. Rocks that contain sand, shale and silt laminated sequences can also appear to be non-pay when in fact they can contain large volumes of gas. Logging with a 3-D resistivity tool can help to highlight laminated sections (thin bed pay) and guide future testing and completions. Production logging has been used to validate the results and highlight the large subsurface uncertainties. Results from an aligned data collection program and the impact on GIIP, URG and uncertainty will be presented. The key to unlocking unconventional resources is sufficient data collection and a close working relationship between a variety of disciplines including reservoir geologists, petrophysicists, geomechanical specialists, completions and reservoir engineers.