Reservoir Characterization

Dr Scott W Tinker
Director of the Bureau of Economic Geology at The University of Texas at Austin

Global trends in energy consumption during the last 150 years have shown a transition from solid carbonbased sources of wood and coal to liquid carbonbased sources of oil and condensate and then to natural gas carbon-based sources of methane (see Figure 1). As the demand for natural gas continues to increase, we will continue to see a greater proportion of natural gas being produced from non-associated (with oil), disseminated or ‘unconventional’ sources. These sources include low permeability (‘tight’), very deep (> 5,000 metres), sub-salt, coal bed methane, shale and frozen gas (hydrates) resources. This trend towards a methane economy will have a positive impact on global economic stability, energy efficiency and the environment.

Figure 1: World Energy Consumption
Source: R A Hefner,III,"New Thinking About Natural Gas", USGS Professional Paper 1,570, 1993, pp.807-829

It has often been said that most of the easily accessible oil and gas has already been found and produced, therefore global oil and natural gas production will come from increasingly more complex reservoir systems (see Figure 2). As complex reservoirs require significant technological understanding and advanced reservoir management plans to make oil and gas recovery economic, the need for advanced reservoir characterisation will increase in the 21st century.

Figure 2: Recoverable Portion of In-place Gas Resources

Source: National Petroleum Council, "Natural Gas: Meeting the Challenges of the Nation's Growing Natural Gas Demand"
Vol.1, Summary Report, 1999. p.96
Unconventional gas, geopressured brines and hydrates not assessed by the National Petroleum Council.

The trend of producing from increasingly complex reservoirs has had an interesting impact on global reserve additions. Over the past two decades, a growing percentage of global reserve additions has come from enhanced recovery in known – and more complex – fields. In other words, we are discovering as many reserves in known fields as we are in new fields, and the ratio is increasing (see Figure 3). This phenomenon, known variously as inferred reserves, reserves appreciation and reserve growth, has been recognised as important for many years but has only recently been included in national reserve estimates and forecasts. Reserve growth (which includes reserves added as an extension of known fields), through reserve estimate revisions by new pool additions and as a function of the application of new technology to improved recovery, is expected to continue to play a major role in future reserve additions globally.

Figure 3: US Reserve Growth

Source: Energy Information Administration, 2002, "US Crude Oil, Natural Gas and Natural Gas Liquids Reserves". 2001 Annual
Report, DOE/EIA-0210, 2001, p. 160

With these global trends (the transition to a methane economy, an ever-increasing proportion of oil production coming from complex reservoirs, natural gas production coming from unconventional reservoirs and an ever-increasing proportion of production coming from known fields), the need for advanced reservoir characterisation to produce fossil energy resources efficiently and economically has never been greater.

The Previous Generation–1-D and 2-D

In the 1950s, ‘development geology’ was largely a onedimensional (1-D) wellbore process. Development geologists in the 1950s did not possess the glamour or prestige of exploration geologists and served largely to support the engineers and help identify ‘good sands’ from which to perforate spontaneous potential and resistivity logs. Fields were being discovered across the US, most on primary production, and well spacing was commonly uniform: 640 or 160-acre spacing for gas, and 40, 20 or 10-acre spacing for oil. The need for advanced reservoir characterisation as we know it today did not exist at that time.

Throughout the 1960s and 1970s, studies of modern depositional systems (1-3)and ancient outcrops, (4,5) led by some of the major oil company research laboratories and supported by several key universities, resulted in advanced understanding of ancient depositional systems in the subsurface. (6,7) Two-dimensional studies of oilfields consisted of linking well log cross-sections supported by qualitative core descriptions between wells and constructing isopach and structure maps to identify sand trends. (7,8) Maps were used to calculate volumetrics and to help design field management strategies. In these two decades, 2-D seismic data resolution was too poor to support development geology, and stratigraphic understanding was not sufficient to help construct adequate reservoir architecture frameworks.

The Current Generation–3-D

For those working in the industry in the 1980s, there was a growing need for secondary and tertiary recovery processes in many of the larger US fields. Development geology became known as reservoir geology, no longer simply a well-based process to identify key productive sands, but instead one of true volumetric reservoir understanding. Multi-disciplinary approaches were beginning to be discussed publicly and recognised for the value they added to the corporate bottom line. Seismic stratigraphy, introduced by several seminal papers in the American Association of Petroleum Geologists Memoir 26, (9) was becoming mainstream for exploration-scale studies but, for the most part, was not yet being applied at the field scale, and reservoir work was still carried out using paper logs, seismic sections and hand-drawn maps.

In the late 1980s and 1990s – with the explosion of computer technology, digital data, 3-D modelling software tools and the early promise of 3-D seismic technology – rock, log, seismic and production data began to be fully integrated into digital reservoir models, visualised in colour and animated in 3-D space. The term ‘flow units’ was introduced as a means to capture the understanding that reservoirs behaved as volumes. (10)
Advanced outcrop studies were being conducted to define the nuances of high-frequency sequence stratigraphy and to place reservoir parameters into a proper stratigraphic framework. (11,12) Lessons from the outcrop were being applied at the reservoir scale to open up new levels of reservoir architecture understanding' (13) and complex 3-D models were being scaled up and used in fluid flow simulation. Modern 3-D reservoir characterisation had arrived. (14-16)

The Next Generation–4-D

When budding geologists starting college during this decade enter the energy industry, theirs will be a 4-D world of instrumented fields and realtime data streaming. They will face many exciting challenges, including the following:

linking matrix properties, diagenetic process and products and fractures of all scales to result in total system permeability understanding;
evolving from a scalar (magnitude) singlecomponent seismic world, through a vector (magnitude and direction) multicomponent seismic world, into a tensor (n^th dimensional space) aniso-tropic seismic world to improve our knowledge of complex permeability and dynamic fluid systems;
processing, interpreting and integrating fourcomponent, 3-D (4-C3-D), nine-component, 3-D (9-C3-D) and nine-component, 4-D (9-C4-D) seismic data with other subsurface data using rock and fluid physics, rather than statistical approximations;
applying land and air-based laser, radar, electromagnetic and other remote sensing technology to advanced 3-D outcrop understanding, and linking that understanding to the subsurface;
designing reservoir management plans, including risk and economic analysis, that take full advantage of the 4-D reservoir understanding; and
applying the remarkable knowledge from the energy industry to broader societal challenges such as sequestration of greenhouse gases, efficient management of the commodity of water and safe disposal of radioactive wastes.

Broader Impacts

For the past 50 years, those in the energy industry have certainly been acquiring all types of surface and subsurface data, cutting-edge computer hardware and software and advanced operational technology to take us to the most remote regions on the planet. As the transition to a gas economy for the nation and the world continues over the next several decades, advanced characterisation, which takes advantage of all of this data, will be critical in order to understand the increasingly complex hydrocarbon reservoirs that will be encountered. Perhaps the medical profession provides an apt metaphor for the energy profession: diagnose before prescribing. Following the metaphor, the 21stcentury challenge for reservoir characterisation and the energy industry must then be to prescribe intelligent, integrated, economic and environmentally sound treatment that takes full advantage of reservoir diagnoses.

Dr Scott W Tinker is Director of the Bureau of Economic Geology at The University of Texas at Austin. He is the State Geologist of Texas and holds the Allday Chair in Subsurface Geology in the university's Department of Geological Sciences. Among the achievements of his 19-year career in the oil industry, he has received best paper recognition in two major scientific journals and has been a distinguished lecturer for the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE). Dr Tinker is a member of many professional societies, boards and committees and is a certified professional geologist and certified petroleum geologist.