The volume of hydrocarbons contained in tight petroleum reservoirs is immense. Thus, their development is crucial to satisfy the worldwide energy demand. A critical aspect for the development of these formations is the stress dependency of rock properties. As pore pressure changes, porosity, permeability, and compressibility of both matrix and natural fractures in tight reservoirs also change, affecting the wells’ production behavior.
A practical problem in the estimation of stress-dependent properties is that the amount of core data available to perform the corresponding studies in tight formations is generally scarce. Under these circumstances, drill cuttings can be used to obtain this information. These observations lead to the key objective of this paper: to develop a reliable approach for estimating stress-dependent properties through the introduction of an innovative methodology that quantifies changes in properties of tight reservoirs and how to extend this methodology in drill cuttings.
The model developed is based on the relationship between the cube root of normalized permeability and the logarithm of net confining stress defined as confining pressure minus pore pressure applied on the rock. An empirical exponent α is introduced to fit the experimental data from confining tests conducted on both vertical and horizontal core samples. This exponent allows the development of an equation that works independently of the initial net confining stress, which is the main limitation of the models already available in the literature. It is our experience that, in many instances, laboratory tests are run at specific values of net confining stress that do not necessarily match the current stress of the reservoir. The correlation proposed in this paper is valuable because it provides a tool that allows correcting the laboratory results to the appropriate net confining stresses in the reservoir. A statistical analysis is performed to verify the appropriateness of the proposed model for the prediction of rock properties as a function of net confining stress.
It is shown that current formulations are particular cases of the proposed model based on the results obtained for the empirical exponent α. Semilog cross-plots of the cube root of normalized permeability versus the net confining stress using core laboratory data corroborate the robustness of the proposed method. The application of the method with drill cuttings is also demonstrated.
It is concluded that the proposed method provides a more accurate methodology for estimating stress-sensitive properties of rocks in tight formations, which are usually naturally fractured, such as the Nikanassin formation analyzed in this work. Porosity, permeability, and compressibility of tight formations are estimated by following the generalized methodology proposed in this study.
Fluid diffusivity inversion and injection-induced microseismicity provide useful means of evaluating unconventional reservoirs. When taking into consideration geomechanics, linear poroelasticity equations provide the key connection between diffusion and microseismicity. This work explores microseismicity generation from a probabilistic point of view, embedding uncertainty assessment in its quantification. Bayesian framework serves as the base for probabilistic analysis.
The primary objective of this work is to develop a new microseismicity probabilistic model framework that can be used for uncertainty quantification in data analysis as well as to provide forward modeling of microseismicity. Results are tested against real data of Horn Rives shales in Western Canada, and show good prediction of the number of actual microseismicity occurrences against time.
The novel probabilistic model is derived from Directed Graphic Model using a statistical learning framework. Stochastic Poisson process combined with a specific rate model is integrated to generate a likelihood function. Both, parameter inference and microseismic event forecast are assisted by Bayesian theorem. The model has an intrinsic statistical learning root, which specifically uses observed microseismic data to update model parameters and then is applied for microseismicity prediction.
The model is extended to take into account basic geomechanical principles.
The novelty of this study is the development of a probabilistic microseismic prediction model which obeys rate-and-state law based relative seismicity rate constitutive equations. The model inherently considers time dependence of nucleation and fault geomechanics. It can be used for planning purposes in the pre-hydraulic fracturing stage.
Huff and Puff gas injection through horizontal wells in shale petroleum reservoirs is moving cautiously from being a promising theoretical possibility, to becoming a reality for increasing oil recovery. This study investigates how oil recoveries from shales can be increased by (1) a combination of refracturing and huff and puff gas injection, and (2) huff and puff gas injection when the length of the gas injection and production cycles are increased over time.
The possibility of improving oil recoveries from shales by a combination of refracturing and huff and puff gas injection is investigated using a compositional simulation approach. Previous studies published in the literature, have considered the implementation of regular constant-time cycles throughout the huff and puff process. This may not be the optimum strategy. In this work, the use of cycles with increasing time-lengths is investigated with a view to maximize the oil recovery by huff and puff gas injection.
The combination of (1) huff and puff gas injection followed by (2) refracturing and (3) stopping gas injection is found to be a good option to increase oil recovery from shale petroleum reservoirs when the initial hydraulic fracturing (IHF) has been successful. The benefits of this approach are demonstrated through a comparison made when refracturing is carried out without previous huff and puff injection. If the IHF has not been implemented properly, the huff and puff gas injection does not provide attractive recoveries. In this case, a refracturing job followed by huff and puff gas injection is shown to improve recoveries significantly. A comparison of the different scenarios considered in this paper shows that proper design of the injection and production schedule is very important in the development of a huff and puff gas injection. Optimizing the schedule by using the appropriate cycles with variable increasing-time spans can lead to improving the huff and puff performance.
This study investigates how to increase oil recovery from shale petroleum reservoirs by (1) the combined use of refracturing and huff and puff gas injection, and (2) the use of cycles of variable length as opposed to the regular-length constant-time cycles considered in previous publications. To the best of our knowledge, the two cases considered in this paper are novel and have not been published previously in the literature.
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values, and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of shale gas reservoirs in the Horn River Basin of Canada. The b-value shows the relationship between the number of seismic events in a certain area and their magnitudes in a semilogarithmic scale. The b-value is important because small changes in b-value represent large changes in the predicted number of seismic events. In this study, b-value is considered as an indicator of the mechanism of observed microseismicity during hydraulic-fracturing treatments.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. On the basis of our definition of an average front curve, we managed to separate most of the microseismic events that are related to natural-fracture activation from hydraulic-fracturing microseismic events. We analyzed b-values for microseismic events of each stage before and after separating fracture-activation microseismic events from original data, and created a map of b-values in the study area. This allowed us to approximately locate activated fractures mostly in the northeastern part of the study wellpad. The b-value map agrees with our assumption of activated-fracture locations and high ratio of seismic activities. The dominant direction of the suggested activated natural fractures agrees with the general trend of the Trout Lake fault zone located approximately 20 km west of the study area.
Suggested fracture direction also agrees with anomalous-events density, energy distribution, and treatment data. We are proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural-fracture-network activation in those instances in which it is not viable to separate events based on their origin.
Primary oil recovery from shales is very low, rarely exceeding 10% of original oil in place (OOIP). The low recovery has aroused a recent and growing interest in the petroleum industry for using Improved Oil Recovery (IOR) methods in shales. This paper presents a new semi-analytical material balance equation (MBE) to forecast the performance of shale oil reservoirs under natural depletion and huff-and-puff gas injection scenarios.
For undersaturated reservoirs, recovery is calculated from the proposed MBE explicitly using a multiporosity effective oil compressibility. For saturated reservoirs, the MBE is solved at each pressure step using a finite differences scheme. For huff-and-puff gas injection, the average reservoir pressure
Results indicate that oil recovery from shales can be increased significantly by huff-and-puff gas injection. A case study from the Eagle Ford shale in the United States is used to demonstrate these results, which are presented in tabular form as well as crossplots of oil rates, cumulative oil production, gas-oil ratio and average reservoir pressure vs. time. An important feature of the proposed MBE is the inclusion of hydraulic fractures, as well as inorganic, organic and natural fracture porosities. These porosities are included in a history-matching presented in detail for a well undergoing huff-and-puff gas injection.
The novelty of this work resides on the introduction of a new MBE that considers multiple porosities and enables quick evaluations of primary recovery and huff-and-puff gas injection scenarios in shale oil reservoirs. The new MBE results compare favorably against real data of the Eagle Ford shale. The good comparison allows making reasonable projections of future oil rates and cumulative oil recoveries by huff-and-puff gas injection.
This paper develops innovative methods for analysis of some important exploration and production problems in shale petroleum reservoirs such as the determination of burial maturity and maturation trajectories, and determination of sweet spots with the use of Modified Pickett plots. The methods are explained with data from 226 Niobrara wells.
Pickett plots have been used historically as a powerful tool for petrophysical analysis of well logs. The plots represent a snapshot on time that corresponds to the time when the well logs are run. Pickett plots rely on pattern recognition observable on log-log crossplots of porosity vs. true resistivity. The analysis has been used in the past primarily for determination of water saturation. However, the plot has been extended throughout the years for evaluation of other parameters of practical importance including, for example, permeability, process or delivery speed (permeability over porosity,
In this paper, Pickett plots are extended from representing a snapshot on time to representing millions of years of burial and maturation trajectories. The proposed method is explained with data from 226 Niobrara wells. The modified Pickett plots leads to curved lines of water saturation (Sw) and BVW. The maturation trajectories on the plot help to explain compaction and why as maturation increases to generate oil and gas condensate, resistivity goes up. However, as maturation increases to generate dry gas in the Niobrara, resistivity decreases. The Lopatin time-temperature index (TTI) is also included in the modified Pickett plot.
The proposed methodology also allows estimating changes in pore throat sizes updip and downdip of a structure, as well as in a basin flank. The ability to combine maturity, pore throat sizes, as well as porosity and process speed in a single graph makes the modified picket plot a valuable tool with potential to locate sweet spots in shale petroleum reservoirs to locate areas for possible improved oil recovery (IOR) and enhanced oil recovery (EOR).
The key contributions of this paper are generating an original method for determining burial maturity and maturation trajectories of shale petroleum reservoirs with the use of modified Pickett plots, as well as determining changes in pore throat sizes in different places of a structure, which lead to the location of sweet spots. Although the methodology is explained with data of the Niobrara shales, it should have application in other shale petroleum reservoirs of the world.
The objective of this paper is to highlight the potential of the Eagle Ford (Cretaceous) and Pimienta (Upper Jurassic) shales in Burgos basin (Mexico) through a comparison with the Eagle Ford shale in Texas. The comparison is a case study focused on real data and their interpretation, north and south of the border, including geochemistry, geology, production, and reservoir engineering data.
The overall approach includes the description of Eagle Ford data in Texas, as well as Eagle Ford and Pimienta data in Burgos basin. The geologic comparison is carried out with the use of cross sections of the various formations and geophysical data. Geochemical and petrophysical data are compared with the use of specialized crossplots. Production data are compared through rate transient analysis and by investigating the different flow periods observed in wells in both sides of the border. Reservoir engineering aspects are compared with the use of material balance methods developed specifically for the case of multiporosity shale petroleum reservoirs.
Results indicate that there are many similarities but also some discrepancies between the Eagle Ford shale in Texas and shales in Mexico. The geologic and seismic cross sections show that there is continuity of the Eagle Ford in both sides of the border. However, structural geology in Mexico tends to be more complex than in Texas. The geologic and geochemistry descriptions also show important similarities in the rock mineralogy, and the quantity, quality and maturity of the organic matter. Well log data show the same pattern distribution on modified Pickett plots developed originally for evaluation of the Eagle ford shale in Texas. Shales production data in the Burgos basin are characterized by very long periods (several months or even years) of transient linear flow, something that compares well with the Eagle Ford in Texas. Specialized material balance calculations, which consider multiple porosities, have been used in the Eagle Ford shale in Texas and are shown to have similar application in the Burgos Eagle Ford and Pimienta shales. Based on the Eagle Ford shale performance in Texas, and the similarities with Burgos shales, the conclusion is reached that there is significant potential in the Mexican Eagle Ford and Pimienta shales.
The novelty of the paper is that it presents a comparison of the interpretation of real geoscience and engineering shale data collected in both sides of the border. The comparison is meaningful and suggests that the potential of shale reservoirs south of the border will be quite significant. Playing its cards right, Mexico should benefit from the good, the bad and the ugly learned in the Texas Eagle Ford.
The objective of this paper is to improve the evaluation and characterization of the fracture network as well as the production matching in the Horn River Shale of Canada. The task is carried out by extending the hybrid hydraulic fracture (HHF) model introduced by
In this paper, the fracture network is discretized using microseismic observations, when available. However, microseismic data may be limited in some of the fractured stages, or like in the case of most hydraulically fractured wells it might be non-existent. The fully coupled HHF model is developed to (1) improve the shale characterization and the simulation history matching, (2) study the fracture closure and permeability change in the fracture network due to gas production, and (3) alleviate microseismic data scarcity by generating a representative fracture network of those stages where microseismic data are unavailable.
The stress change from the initial hydraulic fracturing is evaluated in nine paths multi-level horizontal wells that penetrated the Horn River Shale. The stress shadow is corroborated with microseismic observations and exhibited areas with high fracture density and productivity.
The HHF model further evaluates the reservoir response to pore pressure depletion stemming from production, which leads to stress and permeability changes, fracture closure, and fracture reorientation. The procedure improves the simulation history matching by improving reservoir characterization, especially in stages closer to the toe where an understanding of fracture network geometry is problematic due to the cloud dispersion and scarcity of the microseismicity. The model also evaluates interference between well-paths and helps to determinate the optimum well, fracture and stage spacing.
The HHF model was used to observe changes in volume, permeability and fracture connectivity in undepleted areas close to the fracture network. These areas reveal possible candidates for refracturing. A refracturing scenario that restores fracture conductivity and increases the drainage area of the fracture network is analyzed economically for evaluating the viability of that type of operation in the Horn River Shale.
The HHF simulation model improves the shale reservoir understanding and simplifies the use of a highly complex fracture network for evaluating history matching, fracture closure and permeability changes during gas production. Furthermore, it provides a viable methodology to optimize well and stage spacing, and to evaluate potential refracturing candidates, where microseismic data is unavailable and a fracture network needs to be developed.
The objective of this paper is to present the development and application of a simple equation for calculating asymmetric growth of the stimulated reservoir volume (SRV) in a shale petroleum reservoir using microseismic data.
Calculation of the SRV is a problem handled with solutions that involve different degrees of complexity. Because shale reservoirs are anisotropic, microseismic events generally develop 3D nonuniform asymmetric patterns around the injection points. This paper presents a new method with an easy to use analytic equation that allows reproducing the asymmetric growth of microseismic events as a function of time by considering reservoir anisotropy.
Asymmetric growth refers to the fact that propagation of the microseismic cloud in a given direction can be larger, equal or smaller as compared with the propagation in other directions. Accurate determination of the SRV asymmetric pattern is critical for input in specialized material balance and reservoir simulation models of shale petroleum reservoirs. This determination allows more realistic projections of reservoir performance.
The novelty of the method is the development of an easy-to-use approach for estimating SRV in a spatially nonuniform-asymmetric-anisotropic reservoir using octants in a coordinate system. The SRV is calculated from the volume of a symmetric ellipsoid divided by a constant value
Oil recovery worldwide from conventional reservoirs vary significantly from case to case, but it is sometimes presented at an approximate average of 30-35
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" (
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.