Interdisciplinary integration made easier

The goal of integration has been long sought but seldom achieved. Two of the main obstacles to integration are the lack of a common reference and lack of a common platform. When it comes to the exploitation of unconventional shale reservoirs, there is a need to integrate the disciplines of geomechanics, geopressure and quantitative seismic interpretation. Rock physics is the most obvious link to all these domains.

Rock physics establishes the relationships between the constituents of the rocks, the fabric of the rock, the state of stress, the pressures, the elastic properties and the seismic amplitudes. A software package, RokDoc, has now made this interdisciplinary integration easier with the addition of geomechanical tools to a platform that already includes geopressure and quantitative seismic interpretation. This not only allows for a more integrated approach to understanding and exploiting unconventional shale reservoirs, but it also has benefits for many other workflows.

FIGURE 1. Quantitative geoprediction workflows are shown for (a) unconventional play assessment and (b) natural fracture detection/evaluation. (Source: Ikon Science)

Unconventional shales

Even though shales comprise about 75% of the sedimentary column, studies of the elastic and seismic response of shales are scarce. One of the major differences between conventional reservoirs and unconventional shale reservoirs is the presence of organic matter (also known as total organic carbon or TOC) in shales. TOC consists of bitumen and kerogen. Bitumen dissolves in organic solvents, whereas kerogen does not. When kerogen is subjected to pressure and heat over geological time, it transforms to generate hydrocarbons. This process is known as maturation. Kerogen maturity creates additional pore space in the organic matter. Transformed hydrocarbons are stored in these nano-scale pores. Thus, hydrocarbon production from unconventional shale reservoirs is controlled either by darcy flow (within mineral matrix or in fractures) or by diffusion. The “sweet spot” identification in shale reservoirs usually includes mapping the distribution of organic richness (TOC), thickness of the organic-rich formation, levels of thermal maturity and network of natural fractures. A multidisciplinary approach combining key independent physical properties (e.g. elastic moduli, state of regional and local stress, and geopressure) is required for successful characterization of shale reservoirs.

A quantitative geoprediction workflow

Ikon Science has developed rock physics-based quantitative geoprediction workflows (using multiple sources of data) and has applied them to the number of problems that require a resource-effective approach that can be turned around quickly during drilling operations.

The integrated quantitative geoprediction workflow includes:

1. Identifying incompressibility, rigidity and pore content by facies;
2. Analyzing rock and TOC relationships between the above properties based on core, log and test data from wells;
3. Calibrating elastic, anisotropic and mechanical properties and gradients; and
4. Interpreting most likely indicators (direct lithology indicator for lithofacies, direct TOC indicator for TOC and direct fracture indicator for fracture gradient) associated with reservoir quality and well completion to identify “sweet spots” in a quantitative manner (Figure 1).

In addition to the aforementioned routines, this approach for mapping the lithology and geomechanical attributes uses seismic data inversion. The elastic Lame’s parameters (lambda and µ) that are indicators of incompressibility (lambda rho) and rigidity (µ rho) could be derived from amplitude vs. offset inversion workflows. Figure 2 shows the brittle and ductile zones identified from inversion results.

FIGURE 2. This map of geomechanical attributes uses elastic property space. (Source: Ikon Science)

Geomechanical applications

More than 70% of nonproductive time and increase in drilling costs are related to wellbore-related problems. Geomechanics has many applications, most notably drilling and production optimization. Geomechanical insights help drillers avoid geohazards, plan efficient wellbore trajectories and define safe mud weights. Knowledge of geomechanics aids natural fracture detection, hydraulic stimulation planning and the understanding of the hydraulic fracture propagation. Fundamental to the success of geomechanical applications is a detailed understanding of pore pressure, rock properties and stress state. In the latest RokDoc release, all of the ingredients of a wellbore-centric geomechanical model are combined in one software application.

Local geological and regional geological knowledge can be analyzed by pore pressure experts to delineate a pressure mechanism and predict pore pressure ahead of the bit. By combining this with rock physics modeling, the mechanical properties of different lithologies are assessed from well log data and integrated with formation and core measurements. The system allows for all rock physics, geopressure and geomechanics data to be stored in one database and shared by subsurface domain experts across the disciplines.

Once all of the data are entered into a new project, the core part of geomechanical analysis can begin. Users of the software can diagnose and take action for a wider range of subsurface conditions than before. Consider, for example, wellbore stability-related challenges based on the subsurface stress state, pore pressure and mechanical properties of the lithologic column. The software allows interactive scenario modeling of wellbore stability. As the user changes the planned mud density, the software automatically computes whether this mud density allows safe drilling by analyzing hoop stresses and radial stresses in the wellbore wall and testing whether there is a risk of mud losses, wellbore failure or even wellbore collapse. These safe mud weight limits can be further interactively tested as a function of wellbore inclination and azimuth.

In a production setting it is important to compute the wellbore pressures needed for hydraulic stimulation. It is vital to know whether new fractures are being initiated or pre-existing fractures are being reactivated during hydraulic stimulation. The physical principles adopted in the software make it possible to “know before you go.”

Fracture orientations and densities are detected by image log analysis. Along with the calibrated geomechanical model, injection pressures at which fractures of arbitrary orientation reactivate, whether in tension or in shear modes, are readily computed. In a similar manner, injection pressures required to initiate and propagate new fractures are computed. The uncertainty evaluation of the well productivity has, therefore, become a robust process.

The interdisciplinary workflows that are required to optimize the exploitation of unconventional shale reservoirs are made easier by the recent addition of geomechanical tools to the software platform. The combination of geomechanics with geopressure and quantitative seismic interpretation through the link of rock physics in a common package promises to have great benefits for many other workflows as well.