The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.
A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.
The conclusion is that there is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.
Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs.
Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River
changing the industry's landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific.
Evaluation of well's initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use
of arbitrary "type curves?? can have a significant negative impact on the project's bottom line.
With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional?? production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV),
fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at
numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g.
This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data
analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production
plot is one type curve generally applicable to any shale gas reservoir.
Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale
matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.