Frac fluid delivery is selective in effect, so must fracture models. Here, a physics-based analytical model, called nine-grain model, is presented for production forecasting in multifrac horizontal wells in unconventional reservoirs, where the utilized formulation inherently enables defining three-dimensional non-uniform SRVs, selective frac-hits, and pressure- and time-dependent permeabilities. The model is validated by constructing case studies of liquid and gas reservoirs and comparing the results with numerical simulations. In cases with both production history and fracing-induced microseismic data available, the SRV's spatial structure is extracted using a hybrid four-level straight-line technique that links volumetric RTA estimations to morphometric microseismic analysis and entails plots of plasticity, diffusivity, flowing material balance and early linear flow. By applying our model to an oil well in Permian Basin, we demonstrate that the knowledge gained from the coupled microseismic-RTA contributes to resolving the non-uniqueness of RTA solutions. The proposed reservoir modeling procedure enables efficient incorporation of microseismic interpretations in modern RTA while honoring the SRV space-time variability, thus facilitates informed decision making in spacing design of wells and perforation clusters.
Frac-hits. A frac-hit can be defined as observing a perturbation in the well production rate and/or pressure that is induced by a child offset (or an infill) well, usually triggered by pressure sinks created around parent wells or high permeability lithofacies. A frac-hit that temporarily alters the parent well productivity is called a communication frac-hit, and those with long-term effects, generally caused by fracture interference, are referred as interference frac-hits. A frac-hit may also compromise the productivity of the child well itself since the existing pressure sinks distribute the fracing energy in a larger area and might lead to an asymmetric fracture growth around the child well. Besides the parent well operational condition, the microseismic monitoring of fracing can potentially indicate interference frac-hits as it reveals fracture overlaps and any preferential fracture dilation towards existing wells. Depending on the rock and fluid properties, well age, parent-child horizontal and vertical distances, and the spatial extent of Stimulated Reservoir Volume (SRV), the constructive (Esquivel and Blasingame 2017) or destructive (King et al. 2017, Ajani and Kelkar 2012) effects of frac-hits can be experienced by fractures, SRV or the entire drainage volume (stimulated and non-stimulated zones), usually by impacting rock multiphase fluid interfacial arrangements and/or changing dimensions of conductive fractures. Aside from prevention, thoroughly reviewed by Whitfield et al. (2018), it is essential to incorporate frac-hits into production forecasting models, which to date, is not yet as straightforward as their detection. Both types of frac-hits cause a change in the well productivity over time which is not necessarily correlated with pressure, and hence, complicate the reservoir modeling process.
Distributed vibration sensing has provided a new measurement technique for monitoring hydraulic fracture treatments. We demonstrate that successful existing approaches that integrate pumping parameters and microseismic observations with complex fracture simulation and 3D mechanical earth modelling can be extended to incorporate distributed strain, vibration and flow allocation providing a highly constrained interpretation.
In a monitoring well, where we deploy a hybrid borehole geophone array of 3C geophones for accurate microseismic events mapping, we additionally recover a signal related to static strain from the lowest vibration frequencies of the fibre. From this hybrid cable composed of fiber interconnects and 3C geophones, we may recover extended-aperture information (i) to supplement the geophone-acquired data at microseismic frequencies, (ii) to better constrain hypocenter determination and associated characteristics (e.g., source parameters, attributes, rock failure mechanisms). Furthermore, deploying a fiber within the treatment well, we can recover the relative flow split between the perforation clusters, obtain the bottom hole pressure using the attenuation of the pump harmonics, etc. We integrate these new measurements into the existing geomechanical modelling approach to stimulation interpretation.
We present an example of job planning where synthetic fiber vibrations at the full frequency range and pump data as well as geophone responses are created based on geomechanical and geophysical simulation.
The goal of our work was to maximize gas production and recovery from a horizontal appraisal well in the Mancos shale in New Mexico. This required a fracture design that would maximize perforation cluster efficiency and a lateral placement strategy that would maximize gas recovery. A key challenge was to design a fracture treatment that would overcome the extreme stress shadowing effects. Another key challenge was to optimize the lateral placement balancing multiple factors.
Fracture treatment simulations were completed for various designs. Fracture simulations indicated cluster efficiency could be dramatically improved by optimizing the way we pump the pad. A step-up technique for increasing pumping rates during the pad stage helped to initiate more fractures. Intra-stage diversion was utilized. Fracture simulations were performed to optimize the lateral placement. This required balancing multiple factors to access the highest gas-in-place (GIP) interval yet facilitate more fracture initiations per stage.
Fracture descriptions from the fracture simulations were input to a reservoir simulator to determine the optimal design. This paper will focus on the hydraulic fracture modeling.
This appraisal well was the most productive Mancos gas well ever delivered in the San Juan Basin. The 9,546’ lateral produced at a choke constrained plateau rate of about 13 MMscfd for 7 months and produced over 6 BCF in the first 20 months. A radioactive tracer log indicated an overall perforation cluster efficiency of 83%, a significant achievement in a shale with high stress shadowing.
The fracturing fluid design, diverter design and pumping techniques can be applied in many other shales as a low-cost way to increase perforation cluster efficiency, which will in turn result in higher production rates and higher cumulative recovery. Building on the success observed in the Mancos wells, BP and BPX Energy have subsequently utilized these techniques in other shale plays with success.
The concepts and workflow used to decide the optimal lateral placement is a well-defined approach that can be applied to other unconventional wells to increase hydrocarbon recovery.
Economic hydrocarbon production from organic rich shale has been made feasible by advances in horizontal drilling and hydraulic fracturing. Proppants are pumped to keep the fractures open and provide a high conductive path from the reservoir to the wellbore. Effects of proppant size, proppant crushing, fines migration, rock mineralogy and fluid chemistry on the long-term fracture conductivity have been studied experimentally in detail by Mittal (2017, 2018). This study further investigates the impact of proppant concentration, size and presence of different volcanic ashes on fracture conductivity along with different conductivity impairment mechanisms including proppant crushing, embedment and diagenesis under simulated reservoir conditions.
Experiments have been conducted by varying the proppant concentration of 60/100 mesh Ottawa sand from 2 lb/ft2 to 4 lb/ft2. The proppant pack was placed between metal platens and subjected to axial load of 5000 psi and temperature of 250 °F. Proppant pack conductivity was then measured by flowing 3% NaCl brine for periods of 7-15 days. We observed a sharp decline in permeability, with almost 98% decline within 3 days with low concentration compared to only 60% decline in permeability with higher concentration of proppant. Particle size analysis reveals overall 5% higher percentage crushing at lower proppant concentration, suggesting major crushing occurs at the platen interfaces which reduces with increased proppant pack concentration.
Presence of volcanics in the major shale plays like Eagle Ford and Vaca Muerta has been reported in literature. To simulate similar environment and study the impact of diagenesis on fracture conductivity, experiments have been conducted by flowing high pH (~10) brine through the proppant pack mixed with volcanics like obsidian and basalt and placing the proppant between Eagle Ford shale platens. Experiments were conducted with 20/40 Ottawa sand mixed with obsidian and 60/100 mesh Ottawa sand mixed with basalt. We observed a sharper decline in permeability with 60/100 sand as compared to 20/40 sand in the first two days. However, the permeability for both the proppant sizes continues to decline with a difference of an order of magnitude even after 30 days. SEM images shows significant particle crushing, embedment and diagenetic growth on the shale surface and verify that these factors are responsible for permeability decline. To further understand the impact of proppant size on permeability, dry crush tests have been conducted on 20/40 and 60/100 Ottawa sand by varying compaction pressure from 1500 psi to 3000 psi and 5000 psi. We observed that 60/100 mesh sand undergo overall higher compaction and crushing compared to 20/40 mesh sand at each compaction pressure.
As unconventional plays in North America mature, understanding the performance of step-out and infill wells becomes increasingly important. “Child” well performance has become a major topic of interest because in every unconventional play there exists a significant portion of child wells that perform worse than their “Parents”. It is important to understand how child wells are likely to perform across a play so that engineers can properly forecast production and organizations can allocate capital correctly. The objective of this study was to establish an efficient scoping workflow for understanding the effect of depletion on child well performance across an area of interest, so that promising infill locations can be recognized, and risky infill locations avoided.
The problem with the current parent-child paradigm is that it requires explicitly defining what constitutes a parent, or conversely a child. As described in this study, the choice of definition immediately introduces bias into the interpretation of child performance. A simple function was developed to express the parent child relationship as a continuum, where the influence of parents on a given reference well decays with distance. A workflow was then established to apply the function across a large public well dataset. The workflow handles stacked development, accommodates large scale geological variation and can be efficiently applied over a significant number of wells.
The workflow was applied to areas of interest within the Montney formation in the Western Canada Sedimentary Basin. Results indicate that the depletion function can describe well performance in many areas of interest. Child performance heat maps were generated to identify potential opportunities for infill development. The workflow was also employed to detect performance outliers which could be further investigated to understand child well optimization.
Recent studies have indicated that a substantial percentage of wells “Children” in unconventional plays perform worse on a completion-normalized basis than their predecessors within a defined distance “Parents” (Lindsay et al. 2018). One of the main reasons cited for poorer than expected performance of Child wells is depletion (Cao et al. 2017, Lindsay et al. 2018, Shin and Popovich 2017). Depletion in the vicinity of the child well has the following effects:
Tomassini, Federico Gonzalez (YPF SA) | Smith, Langhorne (Taury) (SmithStrata) | Rodriguez, Maria Gimena (YPF SA) | Kietzmann, Diego (University of Buenos Aires - CONICET) | Jausoro, Ignacio (YPF Tecnología SA [Y-TEC]) | Floridia, Maria Alejandra (YPF Tecnología SA [Y-TEC]) | Cipollone, Mariano (YPF Tecnología SA [Y-TEC]) | Caneiro, Alberto (YPF Tecnología SA [Y-TEC]) | Epele, Bernarda (YPF Tecnología SA [Y-TEC]) | Santillan, Nicolas (YPF Tecnología SA [Y-TEC]) | Medina, Federico (YPF Tecnología SA [Y-TEC]) | Sagasti, Guillermina (YPF SA)
The objective of this work is to present the pore types and their relationship to the main core facies from the Vaca Muerta Formation, Neuquén Basin, Argentina. With an in-house methodology for focused Ion Beam scanning electron microscope (SEM) images and petrographic analysis, a linked to increase the understanding of the pore systems, mineralogy, diagenetic features, grain types and facies variations is carried out. Long continuous cores from two wells were described in detail by standard facies analysis and SEM for semi-quantitatively estimating total porosity, relative abundance of pore types and pore sizes, mineralogy, relative abundance of kerogen and migrated bitumen, type and origin of different clays, and diagenetic quartz abundance among other features. The SEM porosity, organic matter content and mineral distribution correlates favorably with independent measurements obtained by other labs methods. The findings were linked to the core descriptions and the regional sequence stratigraphic framework to predict best reservoir facies. This prediction is done with the production results for each horizontal well in the different landing zones. Finally, the understanding of the pore system can be used to define the best areas and intervals where horizontal wells can be geosteered during the development stage of a block.
The Tithonian-Valanginian (Upper Jurassic-Lower Cretaceous) Vaca Muerta Formation is the main source rock of the Neuquén Basin (Figure 1). The Vaca Muerta Fm. is a lower slope and basinal facies equivalent to the updip Quintuco and Loma Montosa Formations. This formation is a very appealing target for unconventional development due to its vast lateral extent, great thickness (up to 500 m – 1640 ft), relatively high values of total organic carbon (TOC 2-10 %), thermal maturity (oil to dry gas windows), mineralogical composition (less than 30% clay), overpressure and relatively simple structural setting. The study area is located in the center of the Neuquén Basin (Figure 1), north of the Huincul high and mainly in the Añelo depocenter where major activity is taking place. More than 600 horizontal wells have been drilled in the basin in different landing zones resulting in different hydrocarbon production. The EIA (2013) estimated that the technically recoverable resources estimated for this formation are in the order of 300 Tcf of gas and 16 Bbbl of oil and these numbers may be low.
Connectivity of the pore system is crucial for production of hydrocarbons from unconventional resources. In shales, pore throats critically control and limit permeability. Even if larger pores are the dominant pore size, small pores throats could ultimately control the access to that pore space. Mercury injection capillary pressure (MICP) measurements are commonly made to determine pore throat size distributions. Results for shales usually show large injection volumes associated with pore throats just several nanometers in diameter. The existence of these small pore throats has also been confirmed by Focused Ion Beam/Scanning Electron Microscope (FIB/SEM) analysis. One of the unique properties of mercury is that it is non-wetting to both matrix phases present in organic-rich shales; therefore, it can access pore systems in both organics and inorganics. MICP measurements dynamically alter the pore structure through pore compressibility which intrinsically depends on the aspect ratios of the pores; crack like pores, with very high aspect ratios, may close at low pressures and may not be sampled by MICP. The connectivity of the pore space and how much of it is accessed by MICP remains poorly understood.
Here we report on shale samples that have undergone MICP followed by Micro X-ray Computed Tomography (μXCT) and FIB/SEM imaging. μXCT results show that not all regions of the shale samples were accessed uniformly by MICP. Mercury is observed going into fractures and penetrating into the shale matrix. The distance away from the fractures and the percentage of the sample volume accessed by mercury has been calculated. Some samples, such as the Tuscaloosa Marine Shale, showed mercury penetration throughout specific layers in the sample, whereas Eagle Ford samples showed mercury penetration more uniformly and on average of almost 150 μm away from the fractures with almost 60% of the entire sample volume accessed by the mercury. These μXCT results suggest that mercury is not fully accessing all the pore space of the sample even at 60,000 psi which corresponds to a pore throat radius of 1.8 nm.
Cryo FIB/SEM was used to further investigate mercury intrusion into the shale matrix at the nanometer scale. Frozen droplets of mercury were observed in pores as small as 30 nm which corresponds to an injection pressure of 6,000 psi. The mercury clearly accessed the organic pores and remained after pressure was reduced. This is also reflected in the hysteresis observed in the MICP spectra captured during pressurization and depressurization. The magnitude of the hysteresis is a consequence of the differences between pore bodies and pore throats. Like the μXCT, SEM results show that intrusion of mercury into the sample is not uniform indicating that many of the pores are not connected to the outside of the sample. These results suggest that pore connectivity in shales may be very limited, and the volume accessible may not extend far from fractures in the shales.
Rock matrix permeability is a key parameter for characterizing the source rock reservoir and for controlling the well performance over a long period of time. During the depletion of a shale gas reservoir, two important competing mechanisms, among others, impact the gas flow. They are the rock mechanic deformations that reduce the permeability with increasing effective stress and Knudsen diffusion/slippage flow that enhances the permeability at low pore pressures. Therefore, it is important to measure the pore-pressure-dependent permeability to better characterize the fluid flow during gas production. The conventional laboratory methods, based on linearized solutions to gas flow through core samples, measure the pressure-dependent permeability using the “point-by-point” approach. Permeability is measured at a given pore pressure for a given confining stress and then measured again at a different pore pressure so that a pore-pressure-dependent permeability curve can be generated consisting of a number of data points. These methods require multiple test runs and thus are very time consuming. To improve experimental efficiency, we previously proposed a method based on the nonlinear solution to the gas flow equation. This measures the rock matrix permeability as a function of pore pressure using a single test run without any presumptions regarding the form of the parametric relationship between permeability and pore pressure (Liu et al., 2018a). The focus of this paper is to evaluate the previously proposed method through implementation into a carefully designed experimental system (or a nanopermeameter). The validity and practical usefulness of this method is demonstrated by its successful applications to shale core samples and by the consistency between measurement results and those independently obtained from other methods.
Garcia, Artur Posenato (The University of Texas at Austin) | Hernandez, Laura M. (The University of Texas at Austin) | Jagadisan, Archana (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin) | Casey, Brian (University Lands) | Williams, Rick (University Lands)
Reliable formation evaluation in organic-rich mudrocks requires integrated interpretation of well logs and core measurements. More than 80% of the Permian Basin wells have incomplete data sets, lacking photoelectric factor (PEF) or other logs, required for reliable formation evaluation in the presence of complex mineralogy. Hence, we develop a novel workflow to reliably estimate rock properties in wells with incomplete data to enhance reservoir characterization and completion decisions. We propose to (a) use integrated rock classification for enhanced physics-based assessment of rock properties in wells with missing data, (b) combine field-scale geostatistical and machine learning methods to reliably reconstruct missing PEF logs with a confidence interval through a rock-type-based approach which is a unique contribution of this work, and (c) quantify the uncertainty in estimates of petrophysical properties.
We performed a preliminary field-scale formation evaluation on wells with triple-combo logs (more than 70 wells). Next, we performed an initial rock typing and reconstructed the missing PEF logs by combining supervised neural networks with geostatistical analysis on a rock-type basis. We then used an unsupervised neural network method to improve the rock classification based on the updated estimates of petrophysical, compositional, and mechanical properties after PEF reconstruction. The combined rock classification and PEF reconstruction was performed iteratively to improve the multi-mineral analysis results in all wells with missing data. We successfully applied the new workflow to 20 wells in blind tests. The reconstructed well logs agreed with the actual measurements with relative errors of less than 10%.
The new workflow extends the boundaries of reliable formation evaluation, enabling accurate reservoir characterization and completion decisions by enhancing evaluation of wells with missing data. This is achieved by reliably reconstructing missing PEF logs with a confidence interval, in a class-by-class basis, which is a unique contribution of this work. The proposed method can be applied to wells with other types of missing data. Analysis of the production data showed that, ceteris paribus, the best rock types obtained from the workflow had approximately 30% higher hydrocarbon production than other rock types.
In most US unconventional resources development, operators usually first drill the parent wells to hold their leases, and then infill wells are drilled. A challenge raised from this process is the well-to-well interference or frac-hits. Fractures in infill wells have a tendency to propagate toward the depleted region induced by the pressure sink of the parent well, resulting in asymmetric fracture growth in infill wells and frac-hit with the parent well. One of the available mitigation methods is to inject water into the parent well to re-pressurize the depleted region. Though several papers have released positive results from their numerical studies, both negative and positive responses are reported from filed applications. This paper focused on identifying the mechanism and key factors controlling the effectiveness of the subsequent parent well water injection. A coupling reservoir geomechanical model was built to evaluate the pressure and stress change caused by the parent well production and subsequent parent well water injection. The reservoir and geomechanical models are prepared based on a dataset from Eagle Ford Shale. At desired time steps, pressure distribution from reservoir simulation is used to calculate the corresponding stress status.
In this numerical simulation study, both reservoir properties and operating conditions are considered. Considering the production loss during the parent well injection, the maximum injection time is set to be 1 month. The magnitude and orientation of horizontal principal stresses within and around the depleted region are used as a criterion to evaluate the effectiveness of subsequent parent well injection. A general observation is that between two adjacent fracture clusters, 3 regions could be identified whose behaviors are significantly different during production and injection. The subsequent water injection could only restore the pressure and stress in region 1, which is within 10 ft to the fractures. Region 2 is severely depleted but the injection of 1 month generates no improvement in this region due to the low matrix permeability. Region 3 might exist, where oil is not produced, but Shmin reduces and this reduction could not be restored through injection of 1 month. If the injection generates a relatively uniform pressure distribution, then SHmax angle change could be reduced to 0. We also observed that: (1) for our case, an injection pressure equal to the initial reservoir pressure is recommended. Using low injection pressure, Shmin is found out to be lowest in fractures, which may make infill well fractures tend to propagate into and hit the parent well fractures. However, if injection pressure is increased to larger than the initial reservoir pressure and smaller than the minimum horizontal stress, the improvement is insignificant; (2) Comparison between uniform and non-uniform hydraulic fracture geometries shows that hydraulic fracture geometry mainly affects the depletion region far away from the wellbore. i.e. along the long fracture tips. After injection, in the case with long uniform fractures, the Shmin value in long fracture tips is still lowest. (3) An SRV with high permeability significantly extends the depletion region. If the permeability is not large enough i.e. 0.01 mD, after injection of 1 month, the restored Shmin is about 1000 psi lower than the base case without SRV. (4) Using low bottomhole pressure in production, restored pressure and stress are about 500 psi lower than the base case; and due to the large pressure contrast between region 1 and region 2, the SHmax angle change could not be reduced. (5) In a reservoir with normal pressure, as the pressure change is not large, it is easier for the subsequent injection to take effect.
This paper provides significant insights into how to design a successful subsequent water injection process in a parent well, mitigate the negative effects of frac-hits, and maximize production of both parent and infill wells.