A new approach that uses logs derived from wireline and surface drilling data to extract an interface proxy is presented and illustrated in the Montney. The derived interface proxy logs are propagated in the entire reservoir volume using artificial intelligence-based reservoir modeling. Blind wells confirm the ability to predict the interface proxy at any reservoir location. The derived interface proxy propagated in 3D was validated with moment tensor showing that the microseismic shear plane events occur mainly where the presence of the interfaces is the highest.
Using the derived interface proxy as an input, the Material Point Method (MPM) and Anisotropic Damage Mechanics (ADaM) are used to solve the geomechanical modeling of a hydraulic fracture propagating in a layered medium containing any type of interfaces including the weak interfaces. The geomechanical simulation confirms the major impact these weak interfaces could have on the fracture height growth.
The geomechanical analysis confirmed the importance of mapping in 3D the interfaces and modeling their effects in an accurate manner to better capture their effect on fracture height growth and the resulting proppant placement. The application of the new geomechanical workflow was illustrated on two Montney wells and was able to provide some explanation on their production differences that could be attributed to interfaces.
There is an ongoing paradigm shift in the processes and technologies employed in making field development decisions in unconventional reservoirs. Expensive trial and error exercises in multiple reservoirs have returned the verdict: there is no single prescribed treatment for a given reservoir, which always maximizes production and eliminates risk of frac hits and well interferences. In many situations, lateral growth of hydraulic fractures has been the major concern amongst operators, but as the economics of unconventional production shift, and the industry moves to more wine-racking and cube development plans, it has become abundantly clear that current hydraulic fracturing design software have multiple shortcomings such as not being able to fully account for natural fractures and predicting the subsequent frac-complexity as well as including the critical effects of weak interfaces. One of the consequences of this poor representation of the physics occurring during hydraulic fracturing of unconventional wells is the overprediction of hydraulic fracture heights. All commonly used industry frac design software are neither able to predict microseismicity to prove their ability to reproduce the observed frac complexity nor capable of including the effects of weak interfaces, or bedding and laminations (geologically speaking) on hydraulic fracture propagations in the vertical direction. Since microseismicity has been successfully predicted to capture the lateral stress gradients created by the natural fractures, the focus in this study is quantifying at any well the characteristics of the interfaces and their impact on the fracture height. Geomechanical logs derived from commonly available surface drilling data are used to capture zones of high interface potential and their characteristics. The resulting interface positions and their mechanical properties are input in a geomechanical simulator using the Material Point Method (MPM) to simulate the effect of the weak interfaces on hydraulic fracture height growth. These simulations provide the necessary information required by frac design software that now can incorporate not only the lateral stress gradients created by the natural fractures but also the vertical complex effects created by the weak interfaces. The results of this fast-practical decoupled workflow are a better estimate of the spacing needed for wine-rack systems and more realistic fracture geometries inputs to fluid flow models which can provide realistic geometries of depletion profiles affecting well interference potentials driven by production.
The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
Kumar, Abhash (National Energy Technology Laboratory / Leidos Research Support Team) | Hu, Hongru (University of Houston) | Bear, Alex (National Energy Technology Laboratory) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (National Energy Technology Laboratory / University of Pittsburgh)
Hydraulic fracturing involves the injection of large amount of fluid, typically water, in the reservoir rock that increases fluid pressure in the pore spaces and alters the stress condition of the rock significantly. This sudden change in the stress condition is strong enough to create new fractures in the rock or stimulates slip along the pre-existing fractures. Creating new fractures or inducing slip along multiple pre-existing fractures, both results into a marked increase in the interconnectivity of pore spaces and enhance the flow of oil and gas within the stimulated volume. The distribution of microseismic earthquakes that are generated during hydraulic fracturing is traditionally used as a proxy to estimate stimulated reservoir volume (SRV). For efficient extraction of oil and natural gas, it is extremely important to get an accurate estimate of the SRV. However, a simple energy balance calculation suggests that the combined energy released from all microseismic earthquakes during hydraulic fracturing is a small portion of the total input energy, supplied to the reservoir rock in the form of injected fluid. The difference in the total input and output energy suggests some alternate mechanism of deformation in the reservoir rock during hydraulic fracturing that need to be considered to get more accurate estimate of the total stimulated reservoir volume. Recent studies of hydraulic fracturing in the Barnett Shale, Marcellus Shale, Eagle Ford Shale and Montney Shale found the evidence of low-frequency events, with drastically different seismic signature (frequency, amplitude, time duration) than traditional microseismic earthquakes. These low frequency (1-80 Hz) earthquakes are proposed to be associated with either jerky opening or slow rate of slip along pre-existing fractures that are unfavorably oriented in the ambient stress field and releasing as much as 1000 times the energy of an average microseismic earthquake.
We identified multiple long period long duration (LPLD) earthquakes in the surface seismic data recorded during hydraulic fracturing of the two Middle Wolfcamp Shale wells in Reagan County (RC), TX. LPLD events identified in this study show a dominant P-wave signal that persists for 5-10 seconds and significantly long duration compared to traditional microseismic events. We also noticed finite decay in seismic amplitude across the surface-monitoring array suggesting a non-regional or local source of deformation for their origin. We aim to compare and contrast our surface seismic observations on LPLD with seismic data from two 24-tool borehole arrays that were deployed in vertical section of the two nearby treatment wells. This comparison between surface and borehole data will be of strategic importance to evaluate the efficiency of surface seismic monitoring and it would also be helpful in finding more LPLD events in borehole data that are usually less contaminated with the surface noise.
A significant amount of oil is trapped within organic nanopores of shale that cannot be recovered by primary production from these resources. The main reason for the large unrecovered oil volumes in shale reservoirs is the presence of nanoscale pore sizes, which leads to extremely small permeability values, and trapping of hydrocarbons in the adsorbed state on the surfaces the pores. For these resources, effective enhanced oil recovery (EOR) techniques are required to displace oil from nanoscale shale matrix. Due to small permeability, it is difficult, if not impossible, to conduct water and chemical flooding in these resources. Maintaining a stable flood front in immiscible gas flooding is challenging due to the severe fingering phenomenon cause by the naturally fractured nature of these formations. Gas huff-n-puff becomes the most suitable EOR method in shale reservoir development. For decades, carbon dioxide EOR techniques have been successfully applied in conventional reservoirs to improve oil production. In this work, the physics behind CO2 injection into organic nanopores of shale is investigated using molecular dynamics simulations. A 3D kerogen nanochannel, based on the kerogen unit molecules prepared by Ungerer et al. (2014), is created along with a synthetic oil mixture created based on the experimental study of phase behavior of petroleum mixtures performed by Turek et al. (1984). Supercritical CO2 (sCO2) is then injected into the channel at different pressures and oil recovery factors are computed. Results of this study demonstrates that the C7+ component of the oil sample have higher adsorption tendency than lighter hydrocarbon components. Furthermore, it is shown that sCO2 could potentially produce oil, especially lighter components, from organic matters in shale oil reservoirs. It is observed that as sCO2 injection pressure increases, the required soaking time for maximum process performance increases.
Trapped within organic shale matrix, there is a large amount of unrecovered oil content that cannot be removed through primary depletion due to the nanoscale pore size and extremely low permeability values for unconventional reservoirs. Due to these microscopic pore sizes and low permeability values, effective and efficient enhanced oil recovery (EOR) techniques are vital to increasing the oil recovery factor (Kazemi and Takbiri-Borujeni, 2015). Given the properties of these unconventional shale reservoirs, water and chemical flooding become very difficult to perform. Severe fingering effects also take place throughout the fractures within the matrix, adding to the difficulty of gas flooding procedures. With these challenges in mind, gas huff-n-puff becomes the most effective method of EOR for unconventional shale formations. In conventional reservoirs, CO2 gas injection has been a very successful method for increasing the oil production. Given the great success of CO2 gas injection in conventional reservoirs, recent studies have also shown the effectiveness CO2 injection throughout unconventional reservoirs because CO2 has a very high adsorption affinity to the walls of the porous organic matter found within shale gas reservoirs (Jin et al., 2017). By changing the fluid-fluid, rock-fluid, and gaseous interactions by CO2 injection, larger amounts of hydrocarbons can be produced.
Water saturation and permeability are crucial petrophysical properties to evaluate unconventional reservoirs. However, there is no agreement on accurately estimating these properties from logs. Thus, there is a need to develop scale dependent petrophysical correlations to improve the estimation of these properties. As a result, this work aims to use digital rock properties from high-resolution images of unconventional carbonate mudrock samples to develop petrophysical correlations to improve water saturation and permeability estimates. Focused ion beam scanning electron microscopy (FIB-SEM) images were obtained from four carbonate mudrock samples from the Middle East and were segmented into the individual components: calcite, organic matter, pore space, and pyrite. Each image was subdivided into eight sub-sections to study scale dependence. Image analysis provided component details such as porosity, pore size distribution, connectivity, and geometric tortuosity. The impact of varying fluid saturation was investigated by introducing two fluid phases in the segmented pore space. Digital rock (DR) simulations were performed to estimate absolute permeability and electrical resistivity. The results from the DR methodology are discussed with reference to porosity and permeability data from the Gas Research Institute (GRI) method and a relative comparison to the log data is included. The DR results were used to develop petrophysical correlations to predict water saturation and permeability from electrical resistivity. The results show that a limited amount of pyrite and organic matter within a non-conductive calcite framework can change the electrical resistivity by several orders of magnitude. When combined with low porosity, high salinity water, and changing saturation, the results show that some variations in log responses may be attributed to the changing rock matrix and fabric as opposed to saturation. The permeability results also demonstrate that the low porosity, limited connectivity, and resulting tortuosity have a significant impact. These DR-guided correlations may improve the estimates of water saturation and permeability using resistivity logs.
Several frac design models have been developed for unconventional and tight gas reservoirs to predict hydraulic fracture geometries. However, despite the considerable uncertainty associated with estimating the stimulated reservoir volume, these models do not quantify or demonstrate the probabilistic effects on these estimations. Recent field test shows a gross overestimation of the modeled fracture heights (sometimes up to a factor of 2x-3x) due in many cases to the presence of laminations. In this work we introduce a Bayesian methodology for probabilistic hydraulic fracture design that quantifies the uncertainty of predicting the fracture geometry in the presence of geologic factors such as laminations.
To apply Bayesian inference to the deterministic frac design models, the design parameters are linked to the Bayes theorem by assuming the prior distribution is the distribution of frac design parameters before any treating pressure data has been observed. This can be a uniform distribution based on practical ranges of the parameters. The likelihood function is the conditional probability of the observed treating pressures given the frac design parameters. The posterior distribution is the distribution of the frac design parameters after all the available treating pressure data has been taken into account. In a Bayesian model, the goal is to compute the posterior distribution when some amount of data has been observed which in the developed methodology is the observed treating pressure data. The effects of laminations are accounted for in a geomechanical model able to model the weak interfaces and their shearing during hydraulic fracturing. The resulting estimated fracture height is used as a prior in the Bayesian hydraulic fracture model with proppant transport.
The estimated treating pressures are a function of several important variables such as the pressure dependent leak-off, perforation friction coefficient, pipe friction coefficient, reservoir pressure, stresses and other parameters related to the geologic variability. In the Bayesian methodology, the above-mentioned parameters are either assumed to be random variables or their distribution is derived from geologic models instead of assuming deterministic values for the frac design model. This is followed by constructing a Markov chain of the history matching parameters using Markov Chain Monte Carlo with the Metropolis algorithm. Based on the comparison of the simulated treating pressures with the observed treating pressures, the Markov Chain intuitively converges towards the most probable parameters which are then used to quantify the uncertainty in predicting the fracture geometry. The application to the impact of the laminations on the fracture height shows that the Bayesian approach is able to provide a more realistic range of fracture heights much lower than those derived using current models and in line with measured field data.
The proposed Bayesian methodology provides a means to generate probabilistic estimates of complex geologic factors, such as laminations, that have a major impact on the fracture geometry. The resulting fracture geometry is able to account for the all the geologic uncertainties. Interdisciplinary components of Bayesian inference, reservoir engineering and hydraulic fracturing are integrated together with geomechanics to address the important issues of fracture height growth.
The present study provides a comprehensive set of new analytical expressions to help understand and quantify well interference due to competition for flow space between the hydraulic fractures of parent and child wells. Determination of the optimum fracture spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Analytical and numerical model results are combined in our study to identify, analyze, and visualize the streamline patterns near hydraulic fractures, using physical parameters that control the flow process, such as matrix permeability, hydraulic fracture dimensions and assuming infinite fracture conductivity. The algorithms provided can quantify the effect of changes in fracture spacing on the production performance of both parent and child wells. All results are based on benchmarked analytical methods which allow for fast computation, making use of Excel-based spreadsheets and Matlab-coded scripts. Such practical tools can support petroleum engineers in the planning of field development operations. The theory is presented with examples of its practical application using field data from parent and child wells in the Eagle Ford shale (Brazos County, East Texas). Based on our improved understanding of the mechanism and intensity of production interference, the fracture spacing (this study) and inter-well spacing (companion study) of multifractured horizontal laterals can be optimized to effectively stimulate the reservoir volume to increase the overall recovery factor and improve the economic performance of unconventional oil and gas properties.
Rate transient analysis using log-log plots of rate-normalized pressure (RNP) and its derivative (RNP') versus material balance time have proven helpful in providing estimates of shale matrix permeability and SRV drainage volumes in multiple transverse fracture wells (MTFW's) (
We have constructed an analytical model of MTFW's that accurately predicts individual fracture flow performance for both constant and variable rate and constant bottom hole pressure inner boundary conditions. Using this model, we can accurately compute the pressure disturbance and rate change seen at the whole well and for individual fractures to quantify the degree of interference between fractures for any number of parallel, equally-spaced, and equally-sized fractures. This model has been validated by simulation using a commercial simulator. With both this analytical model and a series of numerical simulations, we investigated the fundamental mechanisms of flow in MTFW's and how the estimation of telf may be improved.
Previous authors have represented the progression of flow regimes in MTFW's as a linear flow period that transitions to a pseudo steady state (or apparently boundary-dominated) flow regime. We show that the same flow response is exhibited by a fully-infinite linear system, calling into question the nature of the "stimulated reservoir volume" (SRV) as a bounded reservoir system. In addition, we show telf can be detected and interpreted as the beginning of the onset of this fracture interference using the "limit of detectability" concept.
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
A pressure pumping unit stands ready for water injections into a parent wellhead to prevent damage from frac hits in the North Fork oil field of North Dakota. Frac hits were once a painful cost of doing business for Abraxas Petroleum. But today, the San Antonio, Texas-based shale producer has softened the blows dealt by this widespread and challenging problem. Its approach, called “active well defense,” has been put to the test amid the rolling hills of the company’s North Fork oil field in McKenzie, North Dakota. Instead, active well defense is designed to prevent temporary, yet costly, production stoppages caused by unabated frac hits filling parent wells with sand.