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LiDAR Technology as a Means of Improving Geologic, Geophysical and Reservoir Engineering Evaluations: From Rocks to Realistic Fluid Flow Models
Alfarhan, M. (University of Texas at Dallas) | Deng, J. Hui (University of Calgary) | White, L.S. (University of Texas at Dallas) | Meyer, R. (University of Calgary) | Oldow, J.S. (University of Texas at Dallas) | Krause, F. (University of Calgary) | Aiken, C.L. (University of Calgary) | Aguilera, R. (University of Calgary)
Abstract Outcrops of the Milk River Formation (sandstone, Cretaceous age) at the Writing on Stone Provincial Park in Alberta, Canada have been scanned using ground LiDAR (light detection and ranging) technology. Milk River outcrops represent a real 3D challenge for this technology because of the complexity of hoodoos emanating from pronounced erosion in the area as a result of wind, water and ice following the melting of ice at the end of the last ice age. In addition to the 3D complexity of the hoodoos, the Milk River Formation at Writing on Stone was selected for this project because the geology, studied in detail previously, is characterized by intervals that include a range of sand-rich lithofacies, and is distinguished primarily by subtle differences in grain size and current structures of the sandstones. Also present in the area are relatively flat 2D cliff faces and subvertical fractures. The outcrop exemplifies a challenge for realistic fluid flow modeling. This is of practical importance because these types of rocks develop significant hydrocarbon reservoirs in the Western Canadian sedimentary basin and throughout the world. When buried significant volumes of gas can be trapped in tight formations of similar age. This paper describes an evaluation sequence that includes the planning for LiDAR data collection, actual work and rock sample collection in outcrops, the interpretation and integration with geoscience in a 3D visualization room, and the potential for improved drilling and completion techniques, and reservoir simulation by using the concept โfrom rocks to realistic fluid flow modelsโ. It is concluded that LiDAR provides a powerful technique for sound interpretation of reservoirs rocks and their integration with other sources of information. Introduction The present study was undertaken to test and evaluate the capabilities and limitations of ground-based laser scanning technology (LiDAR) for the construction of reservoir models based on surface outcrops. A multidisciplinary team of the University of Calgary has embarked on a project to investigate and better characterize tight gas/fractured reservoirs, in which the study of outcrop analogues is an integral part. The multidisciplinary research project is called GFREE, an acronym that stands for the integration of geoscience (G), formation evaluation (F), reservoir drilling, completion and stimulation (R), reservoir engineering (RE), and economics and externalities (EE). Before investing heavily in expensive, up-todate LiDAR hardware and software, and in the time and effort of researchers, a pilot study was deemed to be necessary to evaluate the feasibility and usefulness of LiDAR-based mapping/imaging methods. The University of Calgary and the University of Texas at Dallas joined forces to achieve this objective. Herein we report on this pilot study of the various phases in the use of LiDAR, that is, data acquisition, data and image processing, and possible qualitative and quantitative applications of the resulting model. The rocks chosen for the pilot study are the Virgelle Member sandstones at Writing-on-Stone Provincial Park (WOS) in southern Alberta, an area with relatively continuous, superbly exposed outcrops along the Milk River valley.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
Abstract The tank material balance (MB) equation for undersaturated and saturated reservoirs has been written taking into account the effective compressibility of matrix and fractures. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. Historically, compressibility has been neglected when carrying out MB 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 (NFRs) performing below the bubble point, as the fracture permeability and fracture porosity are stress-dependant. Other stress-sensitive properties discussed in this paper include the partitioning coefficient and the exponent for the shape of relative permeability curves. The use of the MB finite difference equations is illustrated with an example. Introduction Forecasting the performance of naturally fractured reservoirs (NFRs) is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility below the bubble point has been usually ignored in MB equations for saturated reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which is the best way to try to solve the problem provided that reservoir characterization and quality of the pressure and production data is good. The objective is to have a tool that can provide a quick indication with respect to potential oil recoveries from stress-sensitive NFRs. Pirson pioneered efforts to try to explain the high GOR associated with many NFRs once the bubble point is reached. He considered the reservoir to be made of two porosity and permeability systems in parallel and visualized production as a succession of equilibrium stages. Jones-Parra and Seijas-Reytor studied the effect of gas-oil ratio on the behaviour of fractured limestone reservoirs using a two-porosity model. They assumed that gravity segregation took place freely and resistance to fluid flow was very small in the fracture network. In the matrix or fine porosity system, there was high resistance to flow and no segregation. Aguilera used combined log analyses and MB to try to explain the high gasoil ratios observed in many NFRs. More recently, Penuela et al. presented a MB for calculating oil-in-place in matrix and fractures taking into account the compressibility difference between matrix and fractures. This paper presents MB equations for predicting oil recovery and rates of undersaturated and saturated reservoirs. The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient, and exponent for shape of relative permeabilities are taken into account. The solution is presented in finite difference form to achieve a quick convergence of the iteration process.
- North America > United States (0.93)
- North America > Puerto Rico > Peรฑuelas > Peรฑuelas (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
Abstract The material balance (MB) equation for stresssensitive ndersaturated and saturated naturally ractured reservoirs (nfr's) has been written taking into ccount the presence of an unsteady state naturally ractured aquifer (nfa). The nfa can be of limited or nfinite size. The solution is presented in finite difference orm to achieve a quick convergence of the iteration rocess. Historically, non-fractured aquifers have been ttached to material balance calculations of naturally ractured reservoirs. This is not realistic from a geologic oint of view as it implies that fractures are present in the il portion of the reservoir but disappear the moment the ater oil contact is reached. It is shown that the use of an nfractured aquifer in a naturally fractured reservoir can ead to erroneous oil recovery estimates. The effect of ater influx on the material balance equation is llustrated with an example. Introduction Forecasting the performance of a nfr subject to water entrance from a nfa is a major challenge. The problem is compounded when the nfr and nfa are stress-sensitive. In this paper the nfr is stress-sensitive, but the nfa is not. The work presented in this paper is not meant to replace a detailed reservoir simulation, which is, in my opinion, the best way to solve the problem, provided that the original oil in place, size of the aquifer, reservoir characterization and quality of the pressure and production data is good. The idea is to have a tool that can provide a quick idea with respect to potential oil recoveries from stresssensitive nfr's affected by water influx from nfa's. Various analytical aquifers have been considered in the literature, most notably those developed by Schilthius Hurst and van Everdingen and Hurst for edge water and Allard and Chen,for bottom water. All of these aquifers considered matrix porosity but ignored the presence of natural fractures. Aguilera, developed equations to account for the presence of natural fractures in unsteady state edge aquifers. The equations were validated by successfully comparing results against those published by van Everdingen and Hurst. This paper presents MB equations for predicting oil recovery of undersaturated and saturated nfr's affected by water influx from nfa's. The nfa can be of limited or infinite size. The infinite case applies, in practice, to those aquifers that are connected with the external world (for example connected with lakes and rives). The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient and exponent for shape of relative permeabilities are taken into account. Unsteady State Naturally Fractured Aquifer Aguilera presented a solution to the problem of nonstressed nfa's following the work of van Everdingen and Hurst. For the case of constant pressure at the inner boundary (constant terminal pressure case) and constant pressure at the outer boundary, the dimensionless water influx is given in Laplace space by: Equation (1) (Available in full paper)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract The tank material balance (MB) equation for undersaturated and saturated reservoirs has been written taking into account the effective compressibility of matrix and fractures. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. Historically, compressibility has been neglected when carrying out MB 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 (nfr's) performing below the bubble point, as the fracture permeability and fracture porosity are stress-dependant. Other stress-sensitive properties discussed in this paper include the partitioning coefficient and the exponent for shape of relative permeability curves. The use of the MB finite difference equations is illustrated with an example. Introduction Forecasting the performance of nfr's is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility below the bubble point has been usually ignored in MB equations for saturated reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which in my opinion is the best way to try to solve the problem, provided that reservoir characterization and quality of the pressure and production data is good. The idea is to have a tool that can provide a quick idea with respect to potential oil recoveries from stress-sensitive nfr's. Pirson pioneered efforts to try to explain the high GOR associated with many nfr's once the bubble point is reached. He considered the reservoir to be made of two porosity and permeability systems in parallel and visualized production as a succession of equilibrium stages. Jones-Parra and Seijas-Reytor studied the effect of gas oil ratio on the behavior of fractured limestone reservoirs using a two-porosity model. They assumed that gravity segregation took place freely and resistance to fluid flow was very small in the fracture network. In the matrix or fine porosity system, there was high resistance to flow and no segregation. Aguilera used combined log analyses and MB to try to explain the high gas oil ratios observed in many nfr's. More recently, Penuela et al. presented a MB for calculating oil in place in matrix and fractures taking into account the compressibility difference between matrix and fractures. This paper presents MB equations for predicting oil recovery and rates of undersaturated and saturated reservoirs. The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient and exponent for shape of relative permeabilities are taken into account. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. General Observations Regarding Oil Recovery In general, if we make a comparison of 2 identical undersaturated reservoirs in every respect, except that one is fractured and the other one is unfractured, we find that the fractional recovery is larger in the undersaturated nfr.
- North America > United States (0.68)
- North America > Puerto Rico > Peรฑuelas > Peรฑuelas (0.24)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
Abstract Conventional wisdom developed throughout many years in the oil industry indicates that a single, closed reservoir can have only one single well-defined water oil contact. Although the contact could appear in some instances to be tilted because of capillary effects, it is still a single water-oil contact. I have observed some instances where a single closed naturally fractured reservoir has two (and even three) different well-defined water oil contacts. This paper gives some ideas to how this can happen. The principles do apply to the case of multiple gas-oil contacts in a closed reservoir, and could be applied in the case of non-fractured reservoirs. I present some guidelines to handle this problem in numerical simulation attempts. The reason is because most numerical simulators will raise an "error flag" if an engineer attempts to input more than one contact within the same simulation in a closed reservoir. Introduction The geological and engineering literature is full of examples showing that single closed reservoirs can have only one well-defined water-oil contact. In fact, the geological/engineering literature has mentioned that having a single water-oil contact is an indication that there is only one oil and/or gas reservoir. Having two or more well-defined water-oil contacts is our indication that there are two or more separate reservoirs. Due to the confidentiality of the data I have examined and the controversial nature of this paper, I have changed the name of the formations where I have observed this phenomena. CONVENTIONAL THEORY Figure 1 shows an example of multiple water-oil contacts (more than 20 WOC's) in separate reservoirs. The example was published on page 239 of Levorsen's book, Geology of Petroleum, from where I quote: "Section through the Santa Fe Springs oil field, California, an example of how many separate traps, holding many separate pools, are formed by one fold. The lack of connection between the different reservoirs is shown in the different water-oil contact level for each productive sand." Figure 1 shows what is conventionally expected. Different water oil contacts in separate pools. But is it possible to have one single, closed reservoir and different water-oil contacts Figure 2A presents a well-accepted case of secondary hydrocarbon migration through the reservoir that does not necessarily end with the first trapping2. In stage one, gas, oil and water are segregated by gravity and all three phases are above the spill point. In stage two, oil reaches the spill point and migrates farther up-dip. In stage three, the anticline is filled with gas. Any oil migrating up at this time will bypass the trap entirely. Continuation of the same sequence of events throughout buoyancy will lead to the four traps in tandem presented in Figure 2B.This is a well-accepted case of multiple gaswater, gas-oil-water, and oil-water contacts in four traps connected with the same aquifer. The cross-section shown on Figure 3 is a corollary from the trapping concept presented in Figure 2. Originally the trap is full with water. Oil migration occurs up-dip following the white arrow until it reaches level WOC1 close to the sealing fault.
Abstract This case history discusses the Palm Valley gas field in Central Palm Valley gas field in Central Australia Production is obtained from a naturally fractured sandstone characterized by a very low matrix permeability (km less than 0.1 md). permeability (km less than 0.1 md). An integrated study including detailed geology, core and log analyses, well testing and numerical simulation led to a good history match of a 33 hour interference test and over 7 years of production. The conclusion was reached that 98% of the gas was stored in a very tight matrix and that the prolific production was only possible via a production was only possible via a network of natural fractures. The methodology used to reach a history match in this case history is presented in detail together with presented in detail together with discussions of critical parameters such as fracture spacing, fracture porosity, and fracture permeability. porosity, and fracture permeability Introduction The Palm Valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig. 1), approximately 120 km. southwest of Alice Springs. The structure is an arcuate anticline mapped from surface expression and seismic data (Fig. 2). The western and eastern plunges of the anticline are poorly defined, however, the anticline poorly defined, however, the anticline axis can be traced for over 40 km. Production from the field commenced in August 1953 with the completion of an 8" pipeline to Alice Springs. Natural gas has been used as a replacement for liquid fuels in electricity generation. Gas production from the field has increased production from the field has increased steadily, currently averaging 141,000 standard m3/d (5 MMSCFD) to Alice Springs. In September 1986 a fourteen inch trunk pipeline was completed connecting the field to the city of Darwin, 1300 km to the north, and to several major towns en-route. Production for this pipeline has Production for this pipeline has reached 622,000 standard m3/d (19 MMSCFD) and again has been used as a liquid fuel replacement in electric power generation. power generation. Development of the field has followed the definition of reserves and during the past 24 years, estimation of the gas reserves has been the subject of many studies; the most significant being by Strobel et al. in 1976; a reservoir simulation study by van Poollen and Associates in 1985 and a recent reserves study by Servipetrol Ltd. in 1990. P. 345
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.85)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.53)
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.66)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Stairway Formation > Lower Stairway Formation (0.99)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Pacoota Formation > Lower Stairway Formation (0.99)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Horn Valley Formation > Lower Stairway Formation (0.99)
- (2 more...)