NATURALLY FRACTURED RESERVOIRS
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WE SPECIALIZE IN THE STUDY OF NATURALLY FRACTURED RESERVOIRS WORLDWIDE
“Many naturally fractured reservoirs are composed of matrix, fractures and non-touching vugs (it can also be any other type of non-connected porosity that can occur, for example, in intragranular, moldic and/or fenestral porosity). An improved triple porosity model is presented that takes into account these different types of porosities. The model can be used continuously throughout a reservoir with segments composed of only matrix porosity, or only matrix-fractures, or only fractures-vugs, or the complete triple porosity system.” A. Al-Ghamdi, B. Chen, H. Behmanesh, F, Qanbari and R. Aguilera, SPE Reservoir Evaluation and Engineering (August 2011).
“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… Because the Nikanassin is considered a continuous gas accumulation [definition by Schmoker (2005)], the results of the present study open possibilities for drilling thousands of Nikanassin wells.”N. Solano, L. Zambrano and R. Aguilera, SPE Reservoir Evaluation and Engineering (June 2011).
“This study presents an integrated workflow for modeling the low permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed based on concepts emanating from an outcrop analog analyzed with terrestrial LiDAR technology and 60 wells that represent the fundamental rock characteristics, structure, facies proportions and petrophysical properties of the Doig Anomalously Thick Sandstone Bodies (ATSB). Structural tops were interpreted from well logs and permeability/porosity relationships established from quantitative log analysis and core-log calibration.”H. Deng, R. Aguilera, M. Alfarhan, L. S. White, J. S. Oldow, and C. L. Aiken, SPE Journal of Canadian Petroleum Technology (May 2011).
“Subsurface fluid injections, such as wastewater disposal, waterflooding, and CO2 sequestration, cause reservoir dilation. The reservoir dilation induces displacements in the overburden extending up to the ground surface and resulting in surface heave. Previous studies have illustrated that it is possible to delineate the extent of the reservoir dilation from the surface heave measurement using an inverse technique. This paper proposes that the inverse technique can be extended to estimate the growth and propagation of the reservoir dilation during the fluid injection if the surface heave is monitored continually.” Li Ping Qiao, R.C.K. Ron Wong and Roberto Aguilera, SPE Journal of Canadian Petroleum Technology (February 2011).
“The importance of North, Central, and South America is highlighted by a hydrocarbon output during 2007 that accounted for 25% of the world oil production and over 31% of the natural gas production. It is concluded that there is a large petroleum endowment in North, Central and South America that will last for several decades and will help to contribute significantly to the energy needs of these regions. It is recommended to actively pursue research and development of this endowment.” Roberto F. Aguilera and Roberto Aguilera, SPE Economics & Management Vol. 2, No. 2 (October 2010).
“A model is developed for petrophysical evaluation of naturally fractured reservoirs where dip of fractures ranges between zero and 90 degrees, and where fracture tortuosity is greater than 1.0. This results in an intrinsic porosity exponent of the fractures (mf) that is larger than 1.0. The finding has direct application in the evaluation of fractured reservoirs and tight gas sands, where fracture dip can be determined, for example, from image logs.” Roberto Aguilera, SPE Journal of Canadian Petroleum Technology (September 2010).
“A method, based on factual observations of naturally fractured reservoirs in several countries is presented for estimating distribution of hydrocarbon cumulative production in wells drilled in fractured reservoirs of types A, B or C. These observations indicate that in reservoirs of type C most of the cumulative production is provided by just a few wells while the majority of the wells contribute a small part of the reservoir cumulative production. In reservoirs of type B the number of wells contributing significantly to cumulative production becomes larger relative to the case of type C reservoirs. Finally in reservoirs of type A, a large number of wells contribute to field production, as compared with type B reservoirs.” Roberto Aguilera, SPE Journal of Canadian Petroleum Technology (August 2010).
“Most tight gas reservoirs we are familiar with contain the presence of natural microfractures. However, these fractures are usually ignored in pressure transient analysis and the reservoirs are evaluated nearly always using single porosity models. One possible reason is the complex behavior of the hydraulically fractured, naturally fractured tight gas reservoir, which causes their build up plots to look sometimes like single porosity reservoirs.” Ashkan Jahanbani Ghahfarokhi and Roberto Aguilera, Journal of Canadian Petroleum Technology (October 2009).
“The petrophysical analysis of fractured and vuggy reservoirs has been an area of abundant interest in the oil and gas industry. For example, a key ingredient for successful completion of wells in naturally fractured tight gas formations is the ability to distinguish gas from water-bearing intervals. Proper estimates of petrophysical parameters, including the porosity or cementation exponent m, play an important role in correct estimations of water saturation (Sw).” “… the change in fracture dip can have a large effect on the value of m. Not taking this into account can lead, in some cases, to significant errors,” Carlos G. Aguilera and Roberto Aguilera, Journal of Canadian Petroleum Technology (July 2009).
“At present, while society is deeply concerned about the environment, hydrogen might emerge as a white knight. There is evidence that, since 1850, the relative hydrogen consumption has been increasing steadily”. “In the case of oil and natural gas, eventually there will be a maximum peak in production. The question is if it will occur sooner or later, and if it will happen because of depletion or because of substitution to other energy sources, perhaps unconventional or non-fossil. Recent work suggests that there are enough hydrocarbons, available at production costs far below current prices, for society to substitute alternative sources before depletion becomes a problem,” Roberto F. Aguilera and Roberto Aguilera, SPE paper 114952 (June 2008). Journal of Petroleum Technology (June 2009).
“To assist with improvements in tight gas recoveries and the economic extraction of this resource we have created the GFREE research program at the Schulich School of Engineering, University of Calgary. The acronym stands for a multi-disciplinary program that involves: (1) Geoscience aspects (G), (2) Formation evaluation by petrophysics and well testing (F), (3) Reservoir drilling, completion and stimulation (R), (4) Reservoir Engineering (RE), and (5) Economics and Externalities (EE). To convert the large Canadian resource into reserves, technological advancements will be required. The GFREE research primarily targets tools and methodologies that will enable producers to quickly, effectively and efficiently assess the economic potential of tight gas resources.” Roberto Aguilera and Thomas G. Harding, Journal of Canadian Petroleum Technology (December 2008).
“A limited amount of information suggests that tight gas formations are generally found in older rocks in the same petroleum provinces where ‘conventional gas’ is produced. This observation, supported by various examples and illustrated with a gas resource pyramid, permits the use of conventional gas formations as a proxy for the presence of tight gas in basins and petroleum provinces throughout the world. A variable shape distribution (VSD) model leads to the conclusion that there is a significant potential endowment in tight gas formations that rivals the endowment from conventional gas accumulations (15,100 tcf). Thus, tight gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 722 quads by 2030.”, Roberto. F. Aguilera, Thomas G. Harding, Federico Krause, R. Aguilera, 19thWorld Petroleum Congress, Madrid, Spain (June 29-July 3, 2008).
presented in this paper leads to what we are calling the “2030 1/3
forecast”. It indicates that global energy needs will be met by
approximately 1/3 of liquids, 1/3 of solids and 1/3 of gases by 2030… If
there is a supply problem in the near future, it will not be the result of
depletion, but rather the failure of society to invest in the research and
development of technology needed to provide conventional oil and gas, as well
as alternatives, on a timely basis.”
“Historically, non-fractured aquifers have been attached to material balance calculations of naturally fractured reservoirs. This is not realistic from a geologic point of view as it implies that fractures are present in the oil portion of the reservoir, but disappear the moment the water oil contact is reached. It is shown that the use of an unfractured aquifer in a naturally fractured reservoir can lead to erroneous oil recovery estimates.” Roberto Aguilera, Journal of Canadian Petroleum Technology (July 2007).
“Historically, compressibility has been neglected when carrying out material balance calculations of conventional reservoirs producing below the bubble point. This assumes that the reservoir strata are static. It is shown, however, that under some conditions, fracture compressibility can have a significant impact on oil rates and recoveries of naturally fractured reservoirs as the fracture permeability and fracture porosity are stress-dependent.” Roberto Aguilera, Journal of Canadian Petroleum Technology (December 2006).
“The underlying but important message is never to overlook low-porosity intervals in naturally fractured reservoirs. It is safer not to use porosity as a cutoff criterion in fractured reservoirs, particularly in exploration wells, unless there is some solid supporting information that asserts the opposite. The use of a porosity cutoff can leave as undiscovered a reservoir that, if tested, could prove to be commercial.” Roberto Aguilera, AAPG Bulletin (May 2006).
“In addition to rock fabric, it is possible to have in a Pickett plot, water saturation, capillary pressure, pore throat aperture, Kozeny’s constant, permeability, process speed, and height above the free water table. The integration of these geologic, petrophysical and reservoir engineering properties permits determination of flow units and a more rigorous characterization of carbonate reservoirs. The method helps to reconcile geology to fluid flow.” Roberto Aguilera, AAPG Bulletin (April 2004).
instances where the reservoir is composed mainly of matrix, fractures and
non-connected vugs. In these cases a triple porosity model appears more suitable
for petrophysical evaluation of the reservoir. A new technique is presented for
these types of reservoirs that is shown to hold for all combinations of matrix,
fracture, and non-connected vug porosities.”
"If total porosities and resistivities of the composite system are used on a Pickett plot when the partitioning coefficient (v) is constant, then the usual straight lines for fixed values of water saturation are not obtained. In this case, the Pickett plot results in downward concave lines. Not recognizing this effect might lead to significant errors in the calculation of water saturation." Roberto Aguilera, Journal of Canadian Petroleum Technology (December 2003).
"Ultimately, the simulation indicated that by producing the largest possible amount of water from the wells in the north and the south of the structure that had been killed by water, the field would be saved and the ultimate gas recoveries would be increased." R. Aguilera, J. J. Conti and E. Lagrenade, SPE Reservoir Evaluation and Engineering (December 2003).
"We have found that some of the models for non-connected vugs fail for certain combinations of matrix and non-connected vug porosities. The reason for the failures is an improper scaling of the matrix porosity." Maria Silvia Aguilera and Roberto Aguilera, Petrophysics (Jan-Feb 2003).
Techniques for evaluation of dual and triple porosity reservoirs, flow units, rock fabric, pore throat aperture, permeability, capillary pressure, and height above the free water table are incorporated in Servipetrol's Fracture Completion Log. The techniques were published recently by Dr. Roberto Aguilera in leading scientific journals of the oil and gas industry.
The scope of projects undertaken range from brief, informal discussions with clients to detailed, fully documented, comprehensive studies. Our final reports include definitive conclusions and recommendations. We can work in conjunction with client geologists and engineers or we can develop completely independent studies.
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