Reservoir Characterization and Performance Prediction of Dual Permeability Tight Gas Systems

Derek C. Longfield¹, Marc R. Junghans¹, and Hank J. Baird^2
1 Compton Petroleum Corporation, Calgary, AB, Canada
² H. J. Baird Petroleum Consultants Ltd., Calgary, AB, Canada

Tight gas reservoirs have become an increasingly important component of new sources of production and long life, sustainable reserves in North America. Many tight gas accumulations occur in widespread ancient channel systems that exhibit variable permeability in all planes, as a result of variations in the depositional energy of the channel system, as well as secondary diagenetic effects. Based on experience with the development of tight gas channel reservoirs in Alberta, Canada, this paper presents a reservoir model that will assist in the efficient and prudent exploitation of these play types. Using detailed engineering and geological analysis, diagnostic computer simulation models can be constructed in a relatively short time frame. If properly characterized, these reservoir models can accurately predict long term well performance, and in so doing, help to define optimum well spacing for the efficient recovery of ultimate reserves. The referenced dual permeability reservoir model exhibits a phenomenon that we call “reservoir linear flow”, which results in markedly different well performance than has been assumed for decades by classical reserve estimation methods.

Much of the research related to optimizing tight gas recovery has focused on creating, optimizing, or evaluating the effectiveness of induced hydraulic fractures, or in detecting extensive and open natural fracture systems. Both of these situations effectively result in an increased wellbore area, which improves well productivity. Production through natural fractures or induced hydraulic fractures also results in linear flow in the reservoir, which, in very low permeability reservoirs, can dominate production behavior for years or even decades. The nature of fluvial reservoir systems dictates that variations in channel course, energy, and sediment source can result in significant heterogeneity in porosity and permeability throughout not only the vertical section, but also over the area of the ancient channel system. This depositional environment can create sizeable lenses of higher permeability rock encased in gradationally tighter matrix rock within the massive channel system. These lenses can approximate the behavior of propped hydraulic fractures, with two significant differences:

• The lens is oriented in the horizontal plane in the reservoir, as opposed to a propped vertical fracture created by an induced hydraulic fracture treatment.
• The areal extent (and therefore area of contact with the matrix rock) can be significantly larger than for an induced fracture, and can be approximated by detailed reservoir analysis and characterization. The impact of this difference on well performance can be significant.

Typical channel systems display a characteristic fining-upwards signature on open hole electric well logs. Compton has discovered and developed several tight gas channel sand reservoirs, with the most prominent being the Hooker Basal Quartz Pool of Southern Alberta, discovered in late 1999 (see Figure 1). This Lower Cretaceous reservoir is a complex channel sequence, up to 125-150 feet in thickness, and grading from basal conglomerate lenses of varying areal extent to sands, silts and shales in the upper portion of the channel. Based on drilling to date, the channel trend is approximately 4-6 miles wide, over 25 miles in length, with an estimated gas-in-place of over1 TCF, and cumulative production of some 55 BCF at December 31, 2004. Compton has developed the majority of this pool on half-section spacing, and undertook the work presented in this study to determine the effectiveness of current well spacing relative to maximizing reserve recovery and economic potential of the pool.

The use of conventional decline curve analysis, analytical models, or type curve methods often results in significant underestimation of long term producing rates, and therefore ultimate recovery of low permeability gas reservoirs. The degree of underestimation can be very significant when only early time data is available, and when decline rates change on a monthly, or even daily basis. While these methods can provide reasonable approximations of early time behavior of homogenous reservoirs, the presence of extensive low permeability rock, and/or significant reservoir heterogeneities can result in considerable departures from these estimates after a few years of production. In almost all tight gas reservoirs, sizeable reservoir pressure gradients exist after the inception of production. In order to develop meaningful pool depletion plans for dual permeability tight gas reservoirs, it is essential to use 3-D numerical simulation models to predict long term behavior of producing wells. In dual permeability tight gas systems, simulation models must be fashioned using both geological and reservoir engineering input, in particular pressure transient analysis, and advanced production data analysis. When carefully constructed, and with the use of reliable flowing pressures, numerical models will assist the operator in planning for suitable well spacing, and will accurately predict ultimate reserve recovery in complex reservoir systems, even with minimal production history.

Compton has constructed models of its dual permeability tight gas reservoirs using the following synergistic process:

1. Using reservoir pressure and permeability values estimated from well test analyses, we first construct a theoretical dual permeability 3-D numerical simulation model to determine the minimum range of matrix permeability that will transmit gas to a high permeability lens in the drainage area of the producing well. This initial step is essential for matching long term well performance, and therefore reserve potential of dual permeability systems.
2. Based on the results of 1) above, we estimate the effective well log porosity cut-off, using measured overburden core permeability measurements from representative wells, as compared with well log response.
3. We construct a net sand map and digitize it into the numerical simulation model.
4. Through the use of well log, core, and well test data and analysis, we initialize the simulation grid blocks in the near-wellbore area by estimating the volume of the higher permeability lens, as well as the transmissibility and thickness of the other sand/silt layers in the channel.
5. We then simulate the initial flow and buildup test of each well in the model with measured production and bottomhole pressure data, and refine the grid block properties as required to history match the test.
6. Using actual production data, with flowing wellbore pressures converted to bottomhole conditions, we match the available historical data with the numerical model. This phase usually requires some minor modifications to the distal grid blocks, as the near wellbore properties should be well-defined if quality core, log, and well test data are available.
7. We prepare forecasts of production under existing and various infill drilling configurations to estimate the optimal spacing for the specific pool under review.
8. For use as an ongoing planning tool, we update the model with production history, and results of infill drilling programs. If necessary, the pool depletion plan can be modified as required.

If care is taken to obtain and analyze high quality geological and engineering data from the onset of discovery, powerful numerical simulation models can be used to accurately predict performance of complex dual permeability tight gas systems. From this work, appropriate depletion plans can be devised, and reliable estimates of reserves can be obtained after minimal production history. This paper presents successful case histories of this approach to reservoir characterization and subsequent pool management.

Figure 1. Thickness map, Lower Cretaceous reservoir, Hooker Basal Quartz Pool, Southern Alberta.