GeoContainment™

GeoContainment™ is the containing of subsurface operations within their designed system. The term is used in the Petroleum Industry relating the subsurface containment of thermal recovery project such as Steam Assisted Gravity Drainage (SAGD) or Cyclic Steam Stimulation (CSS).  It is a vast subject involving the study of geology, geomechanical properties, reservoir parameters, in-situ stresses, and changes in thermal / stress fields during operation.  The concept of GeoContianment™ is also applicable to Solution Mining and Salt Caverns which involve storage of different materials or hazardous wastes underground.

Thermal in-situ recovery involves injecting steam into a reservoir at high pressure in order to mobilize and recover the heavy oil/bitumen.  Rock layers directly above these types of reservoirs are known as the caprock.  The caprock is a non-permeable formation overlying a reservoir or storage cavern acting as a seal.  In order to control the mobility of steam, bitumen, waste or formation fluid, the caprock must display sufficient hydraulic and mechanical integrity to withstand injection pressures in an in-situ production or subsurface storage/disposal scheme.  Evaluation of the underburden seal is also important in some applications to ensure complete GeoContainment™.

In recent years the number of caprock failures in the oil sands and collapses in salt caverns has made subsurface GeoContainment™ critical for public safety and environmental protection.

Core Recovery and Management

Diligent caprock core handling and management is crucial to ensure quality results that accurately reflect caprock properties in the reservoir.

Reliable data begins with capturing the caprock core in a manner that preserves original rock properties. Caprock core must be handled by specialized core handlers since it is highly sensitive to aggressive handling.

Additionally, the core cannot freeze during winter transportation and can dry out in conventional storage which will change its physical properties completely. BGES provides end-to-end caprock core solutions, beginning with specialized handlers and a mobile facility at the wellsite.

After careful cutting and preserving on location, the caprock core is transported, using a specially-designed and environmentally-controlled trailer, to our geotechnical lab in Calgary for further processing.

Geotechnical Laboratory with High-Temp Triaxial Analysis

BGES is home to one of the few high-temp full core triaxial testing apparatus in Calgary, AB. The triaxial tests generate essential inputs for caprock modelling and are therefore necessary to determine caprock integrity in thermal operations. Samples need to be run cold as well as hot since part of the caprock is heated by steam. Therefore, it is imperative that the samples be processed by a lab that specializes in testing caprock core for steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) applications.

During a triaxial analysis, the caprock is placed in a special steel cell that has pressure applied to the side of the sample to represent the effects of the samples being buried underground. The samples are then compressed and the physical properties of the samples are determined. Additionally, the rocks are failed to determine shear strength.

Mini Frac

A critical component of determining caprock integrity is the determination of in-situ stresses, which cannot be measured directly by any tools. Mini-frac (or DFIT) is one of the most common and reliable techniques for indirectly measuring the formation’s minimum in-situ stress.

A mini-frac / DFIT involves pumping test fluid into the formation to create a small fracture that cuts through near wellbore damage to establish communication between the wellbore and the formation. Hydraulic fractures naturally follow the path of least resistance, thus propagating perpendicular to the formation’s minimum principal stress. After pumps are shut down, test fluid leaks off into the formation and the induced fracture closes. This pressure decline can be analyzed to determine when the fracture closes. The pressure at which a hydraulic fracture closes is equivalent to in-situ stress of the formation. BGES’ analysis approach provides consistent interpretation using a combination of diagnostic tools to give the most dependable results.

Step Rate

Step-rate injectivity test has been a proven method for effectively determining the formation parting pressure (or FPP). This pressure is used to define the maximum safe injection pressure into a formation without fracturing the rock in AER’s Directive 51.

During a SRT, injection rate is incrementally increased in steps of equal time. By doing so, a fracture will initiate at a point when the pressure reaches the FPP. Subsequent injection will cause the fracture to grow, producing smaller increases in the pressure although the rate increments remain the same. An adequate initial injection rate, as well as appropriate time steps and rate increments are critical to the success of a SRT. Formation fracture should occur during one of the time steps. For this reason, BGES collects historical well data and uses a test simulator to carefully design the injection scheme. We are well experienced in designing and successfully conducting step-rate tests to satisfy regulatory requirements.

Cold Water Injectivity / Water Mobility Testing

For oilsands thermal simulation models, the bitumen-bearing formation’s water permeability is a valuable piece of information. The cold water injectivity test is a reliable technique for obtaining in-situ permeability data beyond the near-wellbore region. The test involves injecting cold formation-compatible water into the oilsands payzone at very low constant-rates. At the end of the injection, the well is shut-in and the pressure transient is monitored.

This type of tests can help obtain a reliable description of the reservoir water permeability, the initial reservoir pressure and the reservoir’s heterogeneities (layering, fractures, etc.) When multiple wells and/or multiple test intervals are used, a series of test can be designed to detect vertical and/or horizontal communication. For each set of tests, BGES provides a detailed analysis on data collected with a geomechanical review by an industry expert.

Thermal Simulation

Thermal reservoir and geomechanical simulations are conducted simultaneously to predict the stress changes in the caprock during thermal recovery operations. They are necessary to ensure that the steam injected stays in the producing formation supporting production as well as to ensure safe operations. At BGES, simulation is performed by an industry expert with over 30 years of experience in thermal recovery.

Reservoir modelling is heavily dependent on having right input in the model. This involves good data quality control, sound geological interpretation and correct model setup. The reservoir description will typically start with a geological model. Often they are simplified to concentrate on the physical aspects of the caprock. The most critical areas, from a caprock perspective, are selected to provide a maximum operating pressure.

Hydrogeology Study / Analysis

Groundwater resource is an integral part of exploration and production activities. In order to help Operators meticulously manage this valuable resource, BGES offers a wide range of services focusing on the characterization, assessment, development and modelling of groundwater source and movement.