Cumulative Gas Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada

2010 ◽  
Author(s):  
Nisael Solano ◽  
Liliana Zambrano ◽  
Roberto Aguilera
Keyword(s):  
British Columbia ◽  
Gas Production ◽  
Tight Gas ◽  
Gas Formation ◽  
Production Distribution ◽  
Tight Gas Formation

Cumulative-Gas-Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada

2011 ◽  
Vol 14 (03) ◽  
pp. 357-376 ◽  
Author(s):  
Nisael Solano ◽  
Liliana Zambrano ◽  
Roberto Aguilera
Keyword(s):  
British Columbia ◽  
Fractured Reservoirs ◽  
Gas Production ◽  
Distribution Model ◽  
Tight Gas ◽  
Thrust Belt ◽  
Gas Formation ◽  
Production Distribution ◽  
Cumulative Production ◽  
Tight Gas Formation

Summary 271 wells producing exclusively from the Nikanassin and equivalent formations in a very large area of more than 15,000 km2 in the Western Canada Sedimentary basin (WCSB), Alberta and British Columbia, Canada, have been evaluated with a view to determine the distribution of cumulative gas production and the possibilities of intensive infill drilling. The Upper Jurassic to Lower Cretaceous Nikanassin formation is generally characterized as a tight gas formation with low values of permeability (typically a fraction of millidarcy) and low porosities (usually less than 6%). It is likely that natural microfractures and slot pores dominate the productivity of the formation. The study area was divided into six smaller narrow areas (A through F) approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains. Area A is located to the west of the deformation edge, Area B is on the deformation edge, and Areas C through F are located to the east. Area C is the deepest and closest to the thrust belt, whereas Area F is the shallowest and farthest from the thrust belt. Cumulative production characteristics within each area were evaluated with a variability distribution model (VDM) developed recently for naturally fractured reservoirs. The evaluation of each one of the six areas (271 wells) resulted in coefficients of determination, R2 greater than 0.99 in all cases. The results indicate that the gas cumulative production distribution per well is more homogeneous along the deformation edge (Area B), in which 80% of the wells contribute approximately 50% of the cumulative production. The highest heterogeneity was found in Area F (the shallowest), with 80% of the wells contributing only 25% of the cumulative gas production. Areas A, C, D, and E have more or less the same distribution with 80% of the wells contributing between 35 and 45% of the cumulative gas production. In preliminary terms, there is an association between the cumulative-production distribution and lateral variations of borehole breakouts in the Nikanassin formation on a transect perpendicular to the deformation belt of the WCSB. Analysis of the distributions leads to the conclusion that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive drilling to efficiently drain the formation. The possibilities of horizontal wells and multistage hydraulic-fracturing jobs are being investigated at this time.

Experimental and Numerical Evaluation of Water Control and Production Increase in a Tight Gas Formation With Polymer

2019 ◽  
Vol 141 (10) ◽  
Author(s):  
Guangfeng Liu ◽  
Zhan Meng ◽  
Xuejiao Li ◽  
Daihong Gu ◽  
Daoyong Yang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Gas Production ◽  
Tight Gas ◽  
Well Performance ◽  
Water Control ◽  
Polymer Injection ◽  
Gas Formation ◽  
Tight Gas Reservoir ◽  
Production Increase ◽  
Tight Gas Formation

An integrated technique has been developed to experimentally and numerically evaluate water control and production increase in a tight gas formation with polymer. Experimentally, polymer has been appropriately selected and formulated to form a preferentially blocking membrane on the surface of pore and throat in core plugs collected from a tight gas reservoir. The unsteady-state experiments at high temperatures and confining pressures are then conducted to not only measure gas and water relative permeability but also to evaluate the performance of water control and gas production with and without such formulated polymers. The inlet and outlet pressure of the coreholder and flow rates of water and gas are measured throughout the displacement experiments. Theoretically, numerical simulations have been performed to history match the coreflooding experiments and then extended to evaluate well performance in gas fields with and without polymer treatment. Due to the good agreement between the simulated relative permeability and the measured values, the formulated polymer is found to simultaneously control water and increase gas production. Also, it is found from simulation that, after 10 years of production, gas wells after polymer injection show a higher recovery of 10.8% with a lower water-to-gas ratio and a higher formation pressure.

Multistage Hydrocarbon-Based Fracturing in Tight Gas Formation (Russian)

2020 ◽  
Author(s):  
Vladimir Astafyev ◽  
Mikhail Lushev ◽  
Alexey Mitin ◽  
Alexey Plotnikov ◽  
Evgenii Mironov ◽  
...  
Keyword(s):  
Tight Gas ◽  
Gas Formation ◽  
Tight Gas Formation

Exploration of HPHT Tight Gas Formation: First Application of Propped Fracturing in the Offshore Gulf

2015 ◽  
Author(s):  
Al Ameri F. ◽  
Al Awadhi F. ◽  
Abbott J. ◽  
Akbari A. ◽  
Daniels J.L.
Keyword(s):  
Tight Gas ◽  
Gas Formation ◽  
Tight Gas Formation

3D Modeling of Multistage Hydraulic Fractures and Two-Way-Coupling Geomechanics/Fluid-Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin

2014 ◽  
Vol 17 (02) ◽  
pp. 257-270 ◽  
Author(s):  
Laureano Gonzalez ◽  
Gaisoni Nasreldin ◽  
Jose Rivero ◽  
Pete Welsh ◽  
Roberto Aguilera
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Three Dimensions ◽  
Hydraulic Fractures ◽  
Western Canada ◽  
Tight Gas ◽  
Western Canada Sedimentary Basin ◽  
Gas Formation ◽  
Tight Gas Formation ◽  
Canada Sedimentary Basin

Summary Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor. To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB). Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored. The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.

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