The shape of a Polycrystalline Diamond Compact (PDC) bit body is called its profile. It is also the principal influence on bit productivity and stability. The geometry established by the profile contributes to hydraulic flow efficiency across the bit face. Hydraulic flows directly influence ROP through the cuttings removal they provide. If cuttings are removed as rapidly as they are produced, ROP will be relatively higher.
Systems analysis has been used for many years to analyze the performance of systems composed of multiple interacting components. Gilbert was perhaps the first to introduce the approach to oil and gas wells but Mach, Proano, and Brown and Brown popularized the concept, which is typically referred to as Nodal Analysis within the oil and gas industry. The objective of systems analysis is to combine the various components of the production system for an individual well to estimate production rates and optimize the components of the production system. As the fluid moves through the production system, there will be an associated pressure drop to accompany the fluid flow. This pressure drop will be the sum of the pressure drops through the various components in the production system.
Abell, Bradley (W.D. Von Gonten Laboratories) | Xing, Pengju (W.D. Von Gonten Laboratories) | Bunger, Andrew (University of Pittsburgh) | Dontsov, Egor (W.D. Von Gonten Laboratories) | Suarez-Rivera, Roberto (W.D. Von Gonten Laboratories)
Bedding interfaces occur in laminated rock formations at the boundary between different rock types. These interfaces can contribute to fluid leakoff during hydraulic fracturing and thus affect fracture geometry, propped surface area, and the overall hydrocarbon productivity of wells, yet they are only recently being studied. The objectives of this investigation are to empirically measure leakoff into fabricated bedding interfaces and investigate the change in leakoff introduced by fracturing fluid additives, and consequently investigate potential increases in propped surface area and productivity by using fluid additives. A laboratory scale flow cell was developed that accurately simulates hydraulic fractures by allowing for: (i) interfaces that are independent from each other and have adjustable thicknesses that can be changed depending on the proppant being used, and (ii) fracture size and system specifications that produce the same fluid velocities as during field hydraulic fracturing, and (iii) the fluid leaked through the interfaces is continuously collected and weighted, which allows the total leakoff rate to be measured. In addition, the flow cell allows direct visualization of hydraulic stimulations as the entire system is made of visually transparent acrylic blocks. Flow experiments, with clean fluids of different viscosities, were conducted and verified that the measurements agree with theoretical results from lubrication theory. Results of experiments with proppants verified that proppant enters the interfaces for the case when proppant diameter is several times smaller than the interface thickness. And, experiments with cellulose fibers demonstrated that the fibers bridged and accumulated in the regions near interfaces while the main fluid flow inside the fracture developed a tortuous path around these fibers, reducing the leakoff by changing the flow pattern inside the fracture.
Hydraulic fracturing in naturally fractured rocks can potentially generate a complex network of connected fractures. Efficient design of stimulation heavily depends on understanding of the mechanisms of hydraulic and natural fracture interactions and coalescence. Termination or partial propagation of hydraulic fractures might occur in the presence of natural fractures with detrimental effects on the stimulation. Improving fracture design in unconventional reservoirs must be based on a solid understanding of HF-NF interactions in 3D. In this study we cast light on the problem of 3D fracture propagation in naturally fractured rocks and show the potential impact on network design, DFIT interpretation, and proppant transport. Unlike attempts by previous Investigators, we investigate hydraulic fracture propagation in the presence of natural fractures by development and use of a fully 3D coupled model. Our 3D model is based on displacement discontinuity method for the stress analysis and a finite element model for fluid flow calculations. The contact status of natural fractures are determined using contact elements along with the Mohr-Coulomb criterion.
The model simulation results show that the normal and shear stress on the natural fracture are affected by the approaching hydraulic fracture. In the case of hydraulic fracture arrest, the hydraulic fracture can propagate in other directions and tends to engulf the natural fracture. It should be emphasized that capturing the engulfing pattern is only possible through using a robust 3D HF-NF model and other 2D and simpler 3D models fail to predict this geometry. Moreover, as a development, we show and discuss the pumping pressure profile for hydraulic fracturing in the presence of natural fractures obtained from a fully 3D model. The results show that stress shadowing causes non-uniform aperture profiles along the NF which impacts the proppant transport.
Economic production of hydrocarbons from unconventional reservoirs relies on the stimulation by hydraulic fracturing. Extensive research has been directed towards understanding of the reservoir response to stimulation, including experimental, theoretical, and numerical modeling (Blanton, 1982; Koshelev and Ghassemi, 2003a, b; Dobroskok and Ghassemi, 2004; Dobrosko et al., 2005; Zhang and Jeffrey, 2006; Dahi-Taleghani and Olson, 2011; Sesetty and Ghassemi, 2012; 2017; Hu et al., 2019; Ye and Ghassemi, 2018; Kumar and Ghassemi, 2018; Kamali and Ghassemi, 2018; Gao and Ghassemi, 2019; Sesetty and Ghassemi, 2018; Zhang et al., 2009).
Objective/scope – This paper is an extension of the work presented in URTeC paper #2856750, 2018, where a decline curve reproducing the standard transition from linear flow to pseudo steady state flow regimes was proposed for fractured horizontal wells in unconventional reservoirs. In this new work, the formulation was generalized to a succession of flow regimes. This enables the new decline curve to reproduce a succession of periods with power-law behavior, as predicted by recent work on anomalous diffusion models. By construction, this decline curve is fully consistent with RTA concepts and the predictions of physical models.
Method/Procedures/Process – The decline curve is obtained by numerically integrating, in the material balance time domain, a “base function” defined as a succession of straight lines reproducing the successive flow regimes, linked with continuous transition periods. By construction, the base function follows the characteristic evolution of the rate-normalized pressure derivative on a loglog plot, which ensures the physical consistency of the obtained decline curve. Once the curve is matched, its parameters can then be used to infer combinations of physical parameters. Two approaches are possible: (1) In the absence of bottomhole pressures, a classical match and forecast of the instantaneous rate or of the cumulative can be performed in the real time domain directly, with only 3 parameters. (2) If a bottomhole pressure history is available, the evolution of the rate-normalized pressure and its derivative can first be displayed on a loglog plot, where the different regimes emerging can be rigorously identified, and the corresponding lines traced. Once the different straight lines have been positioned, they are automatically linked with continuous transition periods, and seamlessly integrated into the final decline curve. The forecast can be made either by extending the last observed flow regime, or by using a more conservative regime.
Results/Observations/Conclusions – The calculation steps leading to the decline curve are detailed. Comparisons of the results from the decline curve and from various physical models (including analytical anomalous diffusion models with different flow regimes paths) show excellent agreement. Several application examples are shown and the estimation of physical parameters from the parameters of the decline curve is demonstrated.
Applications/Significance/Novelty - The proposed decline curve reproduces the successive emergence of expected flow regimes and is fully consistent with the predictions of currently available physical models – including recent anomalous diffusion models. The parameters of the curve can be used to estimate combinations of the corresponding physical model parameters. As a consequence, the proposed approach bridges the gap between empirical decline curve techniques and the physical concepts used for rate transient analysis.
Hui, Mun-Hong (Chevron Energy Technology Company) | Dufour, Gaelle (Chevron Energy Technology Company) | Vitel, Sarah (Chevron Energy Technology Company) | Muron, Pierre (Chevron Energy Technology Company) | Tavakoli, Reza (Chevron Energy Technology Company) | Rousset, Matthieu (Chevron Energy Technology Company) | Rey, Alvaro (Chevron Energy Technology Company) | Mallison, Bradley (Chevron Energy Technology Company)
Traditionally, fractured reservoir simulations use Dual-Porosity, Dual-Permeability (DPDK) models that can idealize fractures and misrepresent connectivity. The Embedded Discrete Fracture Modeling (EDFM) approach improves flow predictions by integrating a realistic fracture network grid within a structured matrix grid. However, small fracture cells with high conductivity that pose a challenge for simulators can arise and ad hoc strategies to remove them can alter connectivity or fail for field-scale cases. We present a new gridding algorithm that controls the geometry and topology of the fracture network while enforcing a lower bound on the fracture cell sizes. It honors connectivity and systematically removes cells below a chosen fidelity factor. Furthermore, we implemented a flexible grid coarsening framework based on aggregation and flow-based transmissibility upscaling to convert EDFMs to various coarse representations for simulation speedup. Here, we consider pseudo-DPDK (pDPDK) models to evaluate potential DPDK inaccuracies and the impact of strictly honoring EDFM connectivity via Connected Component within Matrix (CCM) models. We combine these components into a practical workflow that can efficiently generate upscaled EDFMs from stochastic realizations of thousands of geologically realistic natural fractures for ensemble applications.
We first consider a simple waterflood example to illustrate our fracture upscaling to obtain coarse (pDPDK and CCM) models. The coarse simulation results show biases consistent with the underlying assumptions (e.g., pDPDK can over-connect fractures). The preservation of fracture connectivity via the CCM aggregation strategy provides better accuracy relative to the fine EDFM forecast while maintaining computational speedup. We then demonstrate the robustness of the proposed EDFM workflow for practical studies through application to an improved oil recovery (IOR) study for a fractured carbonate reservoir. Our automatable workflow enables quick screening of many possibilities since the generation of full-field grids (comprising almost a million cells) and their preprocessing for simulation completes in a few minutes per model. The EDFM simulations, which account for complicated multiphase physics, can be generally performed within hours while coarse simulations are about a few times faster. The comparison of ensemble fine and coarse simulation results shows that on average, a DPDK representation can lead to high upscaling errors in well oil and water production as well as breakthrough time while the use of a more advanced strategy like CCM provides greater accuracy. Finally, we illustrate the use of the Ensemble Smoother with Multiple Data Assimilation (ESMDA) approach to account for field measured data and provide an ensemble of history-matched models with calibrated properties.
Structural dip is the term used in borehole image and dipmeter interpretation to indicate the "tectonic" tilting in the vicinity of the wellbore. Structural dip, by definition, is the formation dip component that is caused by tectonic deformation such as folding, faulting, uplift and others.
Knowledge of the structural dip in the vicinity of the borehole is essential for several applications, including field structural modeling, well placement, geosteering of the lateral sections, and seismic data processing.
Traditionally, structural dip is computed from borehole image data using laminated shale dip based on the assumption that the laminated shale was deposited out of suspension and that the lamination was originally deposited as horizontal beds. This means that any tilting observed in laminated shale with "coherent" lamination is caused by tectonic tilting; hence, it can be used to compute the structural dip. There is nearly a consensus in the industry around this assumption, and the laminated shale dip is widely used to compute structural dip.
There are several geological settings under which laminated shale can form. Those are mostly subaqueous setting such as marine and lacustrine settings. Drilling through rocks deposited in such settings normally encounters sequences of laminated shale from which structural dip can be computed. However, rock formations deposited in subaerial environments often lacks settings under which laminated shale forms. Such environments are often dominated by sandstone lithologies deposited in high- energy settings this rich in sedimentary structures such as crossbedding. Due to absence of laminated shale sequences, computation of structural dip using the traditional approach is not possible.
This paper explains a technique that can be used to estimate structural dip from cross bedding on borehole images. It uses the geometrical relationship between the crossbedding surfaces and the lower set boundary of the corresponding crossbedding set. The line of intersection between these two surfaces is assumed to be horizontal at the time of deposition. Measuring multiple lines of intersections, plotting them on a stereonet, and fitting a great circle to them helps estimate the structural dip within the analyzed interval. The best- fitting great circle of these lines is believed to be a reasonable estimation of the structural dip.
This approach has been tested on few image log datasets with cross bedded sandstone facies and proved to be very close to the actual structural dip computation obtained from the shale facies in the same depositional sequence. This paper will illustrate some interpreted image log supporting this technique.
Huang, Jixiang (Lawrence Livermore National Laboratory) | Morris, Joseph P. (Lawrence Livermore National Laboratory) | Fu, Pengcheng (Lawrence Livermore National Laboratory) | Settgast, Randolph R. (Lawrence Livermore National Laboratory) | Sherman, Christopher S. (Lawrence Livermore National Laboratory) | Ryerson, Frederick J. (Lawrence Livermore National Laboratory)
Jixiang Huang, Joseph P. Morris, Pengcheng Fu, Randolph R. Settgast, Christopher S. Sherman, and Frederick J. Ryerson, Lawrence Livermore National Laboratory Summary A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated. Introduction Factors controlling hydraulic-fracture-height growth have been widely discussed in the literature (Naceur and Touboul 1990). Among them, in-situ-stress contrast between adjoining layers is recognized as one of the principal mechanisms that contain fractures in most scenarios. This is attributed to the fact that source-rock reservoirs are heterogeneous at very fine scales as a consequence of the depositional sequence and subsequent compaction. When a hydraulic fracture reaches a horizon where the stress contrast is high, it might not have the net pressure necessary for propagating into the higher-stress layer (Simonson et al. 1978). For normal-and strike/slip-stress environments, the hydraulic fracture opens against the minimum horizontal stress and propagation is largely within a vertical plane, with the minimum horizontal stress controlling vertical propagation.
Several recent studies have reported that proppant "bridging" (blocking) occurs at the interface between primary and secondary fractures. Such bridging blocks flow and significantly reduces the efficiency of proppant placement. The prevention of bridging is of great importance, but the criteria for bridging formation have yet to be determined. In this numerical study of proppant transport, we propose bridging formation criteria and analyze the associated distribution correlations that quantify the amount of proppant that migrates into the secondary fractures.
To model the complex interactions between proppant particles, fracturing fluids, and fracture walls, we use the discrete element method (DEM) coupled with computational fluid dynamics (CFD). We calibrate our model using widely accepted bed-load transport measurements. The simulation domain involves a "T-type" intersection of primary and secondary fractures. We investigate the effects of various proppant sizes and concentrations on bridging formation. In all cases, we investigate the occurrence of bridging and we quantify its impact by estimating the corresponding percentage of proppant reaching the secondary fractures.
Our simulation results show that the efficiency of proppant placement in the secondary fractures depends on the flow regime. In the suspension regime, proppant particles can be easily mobilized by the fluid drag force. This leads to a relative high proppant placement efficiency in the secondary fractures. When proppants are in the bed-load transport regime, kinetic energy transferred from the fluid drag force is dissipated by inter-particle collisions and the friction force. In this case, the amount of proppants entering the secondary fractures and the distance that proppants can cover are restricted compared to the case of proppants associated with suspension transport.
Our investigation reveals that two parameters are critical for the occurrence of proppant bridging (blocking) at the secondary fracture interface. These parameters are — the proppant concentration
Currently, the closure stress is often predicted using the conventional tangent method (i.e., G-function) or the variable compliance method. Both methods use several restrictive assumptions such as a single planar fracture. However, the hydraulic fracture often intersects rock fabric features such as bedding planes and/or natural fractures causing the pressure transient behavior to become drastically different compared to that of a single planar hydraulic fracture. Closure of the intersected natural fractures might precede that of the created HF which impacts the interpretation of the pressure derivate plots and also the closure stress. In this paper we present and use an advanced fracture diagnostic model that can help recognize the signatures of rock fabric features and their impact on estimation of the closure stress. An example field data is used to illustrate the potential impact on closure stress.
The new DFIT model consists of a fully coupled 3D hydraulic fracture simulator with the ability to handle the opening, propagation, and closure of natural factures so that the pre- and post-closure stress/deformation of both the hydraulic and natural fractures can be captured. Fracture propagation, HF-NF interaction, fracture intersection, and DFIT model are integrated into one simulator to provide a more realistic view of HF propagation and fracture diagnostics in naturally fractured reservoirs. The current model is developed without any major assumptions concerning the fluid flow, fracture deformation, and propagation path. Rock/fracture deformation is calculated using a boundary element formulation whereas the transport processes are solved using finite elements method.
Our results indicate that natural fractures affect the pre- and post- shut-in response of the hydraulic fracture in a number of ways. For example, the fracture propagation path, the pumping pressure profile, and interfering with the post shut-in pressure response. These factors, indeed, impact the estimation of the minimum horizontal stress which is a key parameter obtained from DFIT. Moreover, our results show how the normal stiffness of the fracture surface asperities can impact the minimum stress estimation. Closure of natural fractures is reflected in the slope of the pressure derivative and G-function plots so that correct interpretation of these signatures is essential to accurate extraction of the Shmin.
Closure of natural fractures is often viewed as a pressure depdendent leakoff mechanism that is reflected on the Gdp/dG curve. The closure behavior of HF-NF sets is, however, not explicitly modeled in the context of pressure transient analysis. Therefore, it is our objective to study the closure behavior of HF-NF sets using a 3D coupled simulator. This novel model is applied to actual field data to illustrate the potential impact on closure stress and to shed light on the subject of fracture diagnostics in naturally fractured reservoirs. Our results indicate that the closure behavior of hydraulic and natural fractures in a HF-NF set differs from that of an isolated fracture due to the effect of stress shadowing. Although the system stiffness method results in distinct signatures on the diagnostic curves, these signatures are not commonly observed in the field data. The absence of stiffness signatures in the field cases could be interpreted in two ways: 1) the closure mechanism assumed in the stiffness/compliance method differs from the actual fracture closure mechanism or 2) the stiffness of the hydraulic fracture is too low to cause any significant changes in the system stiffness after closure.