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Results
Evaluation of Flow Units and Capillary Pressures of the Giant Chicontepec Tight Oil Paleochannel in Mexico and a Fresh Look at Drilling and Completions
Gutierrez Oseguera, Alejandra (Schulich School of Engineering, University of Calgary / Now with Kyera Corporation) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary (Corresponding author))
Summary The Chicontepec Paleochannel in Mexico is a giant shaly sandstone reservoir with volumes of original oil in place (OOIP) ranging between 137 and 59 billion STB (Guzmán 2022). However, the oil recoveries are very small, ranging between 0.32% and 0.75% of the OOIP. Under these conditions, consistent interpretation of flow units and mercury injection capillary pressures up to 55,000 psi provide useful information that helps in deciphering the rock quality and pore sizes at levels that might not be reached by thin-section petrography. This is important because the Chicontepec Paleochannel (Misantla-Tampico Basin) has been recently equated to the Permian Basin in the United States and has been termed by Guzman (2022) “a premier super basin in waiting.” The current cumulative oil production of Chicontepec is 440 million STB. Although it is a significant volume, it represents a very small percentage of recovery from the reservoir (0.32–0.75% of the OOIP). To help improve recovery, a method is developed for characterizing the tight Chicontepec Paleochannel using flow units and capillary pressures. Like in the case of many tight unconventional reservoirs, the capillary pressures can go to very high values, reaching 55,000 psi in the Chicontepec case. Therefore, a special procedure is developed to generate a consistent interpretation of all the available capillary pressure curves for the entire range of pressures. The results highlight the important oil recovery potential. The assessment is supported by quantitative formation evaluation work performed by Gutierrez Oseguera and Aguilera (2023). Although natural fractures are present, most wells must be hydraulically fractured to achieve commercial success. Process or delivery speed (the ratio of permeability and porosity) for the Chicontepec samples used in the capillary pressure experimental work range between 159.1 md and 0.17 md (porosity in the denominator is a fraction). Flow units show pore throat radii (rp35) range from less than 0.1 µm to about 4.5 µm. These values and flow units compare well with data available for prolific unconventional reservoirs such as the Cardium sandstone in Canada and the giant Permian Basin in the United States. The radius rp35 refers to the pore throat radius at 35% cumulative pore volume (PV) of injected mercury. This is different from rp also discussed in this paper, which is the pore throat radius at any water saturation (for example, at 40% water saturation). Thus, in the case where water saturation is 65%, rp is equal to rp35. The novelty of this study is the development of a consistent procedure for interpreting the entire range of pressures measured during mercury injection capillary pressures. Such pressures go up to 55,000 psi for the core samples considered in this study. The integration with flow units and formation evaluation suggests that the potential of the Chicontepec unconventional reservoirs can rival successful results obtained in the Cardium sandstone and the Permian Basin. The key ideas discussed in this paper for improving Chicontepec oil recovery include specialized petrophysical evaluation, determination of flow units and capillary pressures, improved drilling and completion methods, and geological support.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.96)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (58 more...)
Evaluation of Flow Units and Capillary Pressures of the Giant Chicontepec Tight Oil Paleochannel in Mexico and a Fresh Look at Drilling and Completions
Gutierrez Oseguera, Alejandra (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract The Chicontepec Paleochannel is a giant shaly sandstone reservoir(s) with volumes of OOIP ranging between 137 and 59 billion STB (Guzman, 2019), which has been equated recently to the Permian Basin. However, the oil recoveries are very small, ranging between 0.32 to 0.75% of the OOIP. Thus, the objective of this study is to evaluate flow units and capillary pressures of Chicontepec, as well as drilling and completion methods, with a view to improve the characterization of the reservoir(s) and, thus, oil recoveries. Current cumulative oil production of Chicontepec is 440.38 million STB. Although it is a significant volume, it represents a very small percent recovery from the reservoir (0.32 to 0.75% of the OOIP). To help improving recovery, a method is developed for characterizing the tight Chicontepec paleochannel using flow units and capillary pressures. Like in the case of many tight unconventional reservoirs, the capillary pressures can go to very high values, reaching 55,000 psi in the Chicontepec case. Therefore, a special procedure is developed to generate a consistent interpretation of all the available capillary pressure curves for the entire range of pressures. Results highlight the important oil recovery potential of the Chicontepec Paleochannel (Misantla-Tampico Basin), which has been equated recently to the Permian Basin in the United States and has been termed by Guzman (2022) "a premier super-basin in waiting." The assessment is supported by quantitative formation evaluation work performed by Gutierrez Oseguera and Aguilera (2022). Although natural fractures are present, most wells must be hydraulically fractured to achieve commercial success. Process or delivery speed (the ratio of permeability and porosity) for the Chicontepec samples used in the capillary pressure experimental work range between 159.1 md and 0.17 md (porosity in the denominator is a fraction). Flow units show pore throat apertures (rp35) ranging from less than 0.1 microns to about 4.5 microns. These values and flow units compare well with data available for prolific unconventional reservoirs such as the Cardium sandstone in Canada and the giant Permian Basin in the United States. The radius rp35 refers to pore throat aperture at 35% cumulative pore volume. The novelty of this study is the development of a consistent procedure for interpreting the entire range of pressures measured during mercury injection capillary pressures. Such pressures go up to 55,000 psi for the core samples considered in this study. The integration with flow units and formation evaluation suggests that the potential of the Chicontepec unconventional reservoirs can rival successful results obtained in the Cardium sandstone and the Permian Basin. Some ideas are advanced regarding drilling and completion for Chicontepec based on the results of the present study and production success in the Permian Basin.
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.95)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (40 more...)
A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates
Azuara Diliegros, Brenda (Schulich School of Engineering, University of Calgary (Now with Pemex in Villahermosa, Tabasco, Mexico)) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary (Corresponding author))
Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.
- North America > Mexico (1.00)
- North America > United States (0.93)
- North America > Canada > Alberta (0.29)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Turonian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Cenomanian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Aptian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Albian (0.46)
- North America > Mexico > Tamaulipas > Burgos Basin (0.98)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.98)
- North America > Mexico > Coahuila > Burgos Basin (0.98)
- (17 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
The Fundamental Role of Electrostatic Forces Within Pore Systems and Their Effects on Resource Evaluation and Reservoir Performance: Capillary Forces Theory
Lee, Robert (University of Calgary) | Pedersen, Per K. (University of Calgary) | Moslow, Thomas F. (University of Calgary) | Aguilera, Roberto (University of Calgary)
Abstract This study is focused on understanding an unrecognized class of resources herein termed semi- conventional resources. These resources share the common characteristic that the combination of reservoir and in- situ fluid properties result in low effective permeability to the primary free fluid, crude oil. They have much closer affinity with conventional resources than shale or thermal bitumen resources. Unpublished work by the primary author examined reservoirs with oils ranging from 12-34°API and permeabilities ranging from 1-500mD across dozens of developed and undeveloped resource accumulations in western Canada. These resources also share common issues with resource evaluation and reservoir performance. Those issues can be better understood through knowledge of the role of electrostatic forces within pore systems. Capillary Forces Theory (CFT) provides a new model and data interpretation framework that integrates physics, engineering, petrophysics, and geology into a new understanding of the fundamental forces within pore systems. The CFT model and data interpretation framework is developed from two simple principles. All pore system surfaces have a permanent, intrinsic electrostatic charge at grain and crystal surfaces due to termination of covalent balancing of atomic lattices. Since this field is an atomic property, the strength and extent of the electrostatic field is the same regardless of grain or crystal size. Therefore, the relative influence of the surface fields increases exponentially as pore system aperture size decreases. The second principle is that water is strongly polar so has affinity for charged surfaces. These principles play a critical role in three reservoir processes. Firstly, electrostatic forces are the energy that resists displacement of pore water from wet reservoirs during hydrocarbon emplacement. These forces are measured with capillary pressure drainage curves. Secondly, the capillary film water and oil phases are immiscible but also bonded to some degree by polar components within the oil that can bridge the interface. This is a poorly understood issue and the fundamental cause of the Effective Drainage Area Problem. The Effective Drainage Area Problem is defined by; Counter to generally accepted reservoir modelling, original pressures, fluid saturations, and/or fluid contacts are encountered when infill drilling or reducing frac spacing. The CFT model indicates oil in a pore system will not move until the bonding forces between the fluid phases and/or surface fields are exceeded, something that is not directly measurable at this time to this author's knowledge. Thirdly, imbibition, the spontaneous uptake of water, is the response to intrinsic, pervasive electrostatic imbalance within pore systems with partial oil saturations when reservoir conditions change. Exposing a reservoir with partial oil saturations and saline capillary film water to higher pressure fresh water via drilling or fracturing has complex effects. The capillary film is always at lower pressure than the free fluid, the introduced fluid is miscible with the capillary film but immiscible with the free fluid, and anchoring across the interface by polar components tends to bond the capillary film and free fluid to some degree. There is also potential for significant osmotic pressure because of the high salinity contrast between introduced and connate water. This enhances imbibition. The CFT model and data interpretation framework provide the theory and practical tools to understand how small forces on an absolute scale can have significant impact at the scale of pore systems and is the basis for recognition and evaluation of semi- conventional resources.
- North America > Canada > Alberta (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline (0.94)
- Geology > Petroleum Play Type > Unconventional Play (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
Method for Drawdown Analysis of a Multi-Stage Hydraulically Fractured Horizontal Well That Penetrates an Unconventional Naturally Fractured Reservoir
Gutierrez Oseguera, Alejandra (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract This paper examines the pressure response of a horizontal well that penetrates an unconventional, naturally fractured reservoir. The response is quite surprising. The expectation of linear flow is shattered, and only radial flow is observed. The radial flow two parallel straight lines in a semilogarithmic crossplot of flow pressure vs. time are present but they are reversed, with the last straight line showing smaller pressures as compared with the extrapolated first straight line. Two different methods are used; the first one is a conventional approach for analyzing the first semilog straight line with a view to calculating flow capacity and permeability well as skin. The second approach involves a novel dual porosity model that permits calculating several fracture parameters of interest, and to the best of our knowledge has not been published previously in the petroleum engineering literature. In this paper, new equations with a semi-empirical component, are presented that allow matching the reversed real pressure drawdown data as well as the corresponding pressure derivatives. The new model shows that fluid flow is dominated initially by the fractures as in the case of dual porosity conventional models. In the conventional model, flow pressure data deviate from the first straight line toward the right due to pressure support stemming from fluids that move from the matrix toward the fractures. Eventually, a pressure equilibrium is reached and a second straight line, parallel to the first one, is developed. However, in the case of the model presented in this paper the data deviates, not to the right of the first straight line, but down and below the first straight line. This pressure drop is interpreted to be the result of boundary-dominated flow. Next, a pressure equilibrium is reached between matrix and fractures, and the last line becomes parallel to the first straight line. It is shown that correct pressure and derivative matches permit estimating various parameter of interest such as size of the matrix blocks, number of fractures that intercept the well bore, storativity ratio omega, partitioning coefficient (the ratio between fracture and matrix porosity), matrix permeability, and the ratio of fracture to matrix hydraulic diffusivity. The novelty of this study is the development of a new easy-to-use well testing model for matching an unconventional pressure response during drawdown of a horizontal well that penetrates an unconventional tight dual porosity reservoir. The new method is explained with a step-by-step example that uses real data from the giant unconventional Chicontepec paleochannel in Mexico and can be reproduced readily by the reader.
- North America > Canada (0.28)
- North America > Mexico (0.25)
Abstract This paper develops a new method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. Development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with more than 0.1md. The method is calibrated with data from cores and cuttings and allows estimating the presence of grainstone, packstone and wackstone rocks in unconventional tight carbonates from well logs. A crossplot of RFN vs rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that is supported by well testing data. Information for analysis of the Mexican carbonate comes from well logs of 9 wells and 2 re-entry wells, four buildup tests and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95 percent of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md. Thus, the need for a methodology that allows estimating from well logs the presence of grainstone, packstone and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico. The novelty of this paper is the use of rock fabric (RFN) in unconventional tight carbonates with permeabilities smaller than 0.1 md for estimating the presence of grainstone, packstone and wackstone rocks from well logs. In addition, a crossplot of RFN vs rp35 provides a good indication of intervals with oil production potential.
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Turonian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Cenomanian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Aptian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Albian (0.46)
- North America > Mexico > Tamaulipas > Burgos Basin (0.98)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.98)
- North America > Mexico > Coahuila > Burgos Basin (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Summary The average reservoir pressure is a key parameter in material-balance calculations, but its determination is challenging when dealing with shales because of their low and ultralow permeabilities. This paper presents an easy-to-reproduce methodology for calculating the average reservoir pressure from flowing data, and its use in a new material-balance equation (MBE) that considers the simultaneous contribution of free, adsorbed, and dissolved gas. The procedure developed in this paper uses a modified gas-compressibility factor (Z′) introduced in the new MBE. Because Z′ accounts for the combined effect of free, adsorbed, and dissolved gas, then total original gas in place (OGIP) can be determined from extrapolation of the MBE straight line to an average reservoir pressure equal to zero. Drainage area can be estimated on the basis of calculated OGIP and volumetric equations. As such, the methodology offers the potential to help improve well spacing in shale gas reservoirs in such a way that no stranded gas is left in the reservoir, or that excess wells are not drilled in the field. This can help to improve recoveries from shales by assisting in the determination of the optimal number of wells needed to drain a given play efficiently. In conventional reservoirs, a well is shut in, and the average reservoir pressure is determined from the corresponding pressure-buildup test. But, for the case of unconventional shale gas reservoirs, shutting the wells in is unacceptable because of the long time it would require for estimating average reservoir pressure. The methodology developed in this paper for shale gas reservoirs circumvents this problem by using dynamic data. Production data from multistage hydraulically fractured horizontal wells completed in a Canadian shale gas reservoir are used for testing the effectiveness of the new methodology. Comparison of typical well-spacing values vs. the drainage area calculated with the new methodology leads to the conclusion that, probably, only 40% of the gas is being drained efficiently. The novelty of this work relies on the development of a methodology for calculating average reservoir pressure, OGIP, drainage area, and optimal well spacing in shale reservoirs through the combination of dynamic data and a new MBE that considers simultaneously the effects of free, adsorbed, and dissolved gas.
- South America (1.00)
- North America > United States (0.93)
- North America > Canada > British Columbia (0.72)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.15)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
This observation leads to the objective of this paper: to examine geoscience and engineering data of tight and shale reservoirs in Mexico with a view to estimating the oil and gas endowment, and to determine the economics of developing these plays under current and forecast possible oil and gas prices. Plays considered in this study include the Burgos, Sabinas, Tampico, Tuxpan (Platform), Veracruz, and Chihuahua Basins. Endowment is defined by the US Geological Survey (USGS) (USGS 2000) as the sum of known volumes of oil and gas (cumulative production plus remaining reserves) and undiscovered volumes. The economics of these plays is examined with the use of cumulative long-run supply (or availability) curves. These are presented as crossplots of production costs per barrel of oil or per Mcf of gas vs. endowments for the aggregate of basins, and are very useful to demonstrate how endowment volumes vary at different price levels. It is concluded that the potential of unconventional resources in Mexico is quite significant and will help to change the slope of production rates in the country from negative to positive. As a result, it is anticipated that Mexico will become an important part of the shale-petroleum revolution started in the US.
- North America > United States > Texas (1.00)
- North America > Mexico > Veracruz (0.68)
- Phanerozoic > Paleozoic (0.68)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic (0.47)
- Phanerozoic > Cenozoic > Paleogene > Eocene (0.47)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- (6 more...)
- Geophysics > Borehole Geophysics (0.67)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Government > Regional Government > North America Government > Mexico Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Edwards Formation (0.99)
- (34 more...)
Breaking a Paradigm: Can Oil Recovery from Shales be Larger than Oil Recovery from Conventional Reservoirs? The Answer is Yes!
Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract Oil recovery worldwide from conventional reservoirs vary significantly from case to case, but it is sometimes presented at an approximate average of 30-35 % of the original oil in place (OOIP), including primary and secondary recovery. This study shows that proper implementation of huff and puff gas injection in shales can lead to larger percent oil recoveries. Explaining the reasons for this controversial and out of the box conclusion is the key objective of this paper. This research starts by investigating flow units and pore throat sizes of shales, and by demonstrating the separate ‘upside-down’ or inverted vertical containment of natural gas, condensate and oil in shale reservoirs. Once vertical containment is demonstrated with data from the Eagle Ford shale in Texas, the research moves to investigating huff and puff gas injection in hydraulic fractured horizontal wells. The investigation is carried out by considering theoretical, core, laboratory, and petrographic data; and a simulation match and economics of an Eagle Ford huff and puff gas injection pilot. Results, dramatic and that no doubt will become highly controversial, lead to the out of the box conclusion that oil recovery with correctly-performed huff and puff gas injection can lead to oil recoveries even larger than oil recoveries from conventional reservoirs, reaching levels of up to 40%+ of the OOIP in the oil container. The finding is important as oil recoveries from shales have been reported up to this point in the literature to be very low ranging between approximately 5 and 10 %. The term "container" is not used generally in petroleum engineering, but proved of significant value in our research. A container is "a reservoir system subdivision, consisting of a pore system, made up of one or more flow units, which respond as a unit when fluid is withdrawn" (Hartmann and Beaumont, 1999). Although this investigation is carried out only for the Eagle Ford shale of Texas, preliminary scoping studies indicate that a similar potential might exist in other tight and shale reservoirs such as the Duvernay, Montney and Doig reservoirs in Canada, and Vaca Muerta in Argentina. The key contribution of this paper is highlighting the extraordinary potential of huff and puff gas injection in shale petroleum reservoirs, which can increase oil recoveries to even higher levels than the recoveries commonly achieved in conventional oil reservoirs. Economic benefits as a result of huff and puff gas injection in shales are included in the paper.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (15 more...)
Summary This research presents a new method to analyze production- and well-test data: the superposition rate. The method was developed from the well-accepted superposition principle. It is presented in a generalized form and is applicable to data in transient flow (including radial, linear, and bilinear), as well as in boundary-dominated flow (BDF). The superposition-rate method is validated by synthetic data generated from reservoir modeling. Moreover, a practical work flow of implementing the superposition rate in production-data and well-test analysis is presented. Finally, real-field examples are used to demonstrate the practicality of superposition rate. A comparison between the superposition-rate and superposition-time methods is presented. The superposition rate shows advantages over the superposition time. A key improvement of the superposition rate in quality diagnostics and data analysis is that it does not modify time scale. Consequently, the superposition rate keeps all production data in the sequence of their occurrence.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Anderson Field > Canlin Andersn 11-3-51-23 Well (0.93)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)