Searles, Kevin H. (ExxonMobil Upstream Research Co.) | Zielonka, Matias G. (ExxonMobil Upstream Research Co.) | Ning, Jing (ExxonMobil Upstream Research Co.) | Garzon, Jorge L. (ExxonMobil Upstream Research Co.) | Kostov, Nikolay M. (ExxonMobil Upstream Research Co.) | Sanz, Pablo F. (ExxonMobil Upstream Research Co.) | Biediger, Erika (ExxonMobil Upstream Research Co.)
This paper describes the development, validation, and application of new 3D finite element models for a diverse set of oil & gas problems involving fluid-driven fractures. Applications described in the paper include borehole integrity and lost returns, drill cuttings re-injection (CRI), and produced water reinjection (PWRI).
The models were developed and implemented in a commercially available finite element (FE) software package. The models include both cohesive elements (mesh conforms to pre-defined fracture orientation) and extended finite elements (fracture geometry evolves independent of the finite element mesh). Advantages and disadvantages of each approach will be described. The models were validated through comparisons with published analytical asymptotic solutions for limiting values of rock and fluid properties and leak-off conditions (with practical problems of interest lying within these limits). A comprehensive suite of large-scale laboratory experiments were also conducted and models were used to replicate the conditions and results of these experiments. Larger 2D and 3D finite element models were then constructed and used to demonstrate applicability to a broad range of realistic oil & gas problems, including problems with large length and long time scales. Tractable simulation of these problems was enabled by high-performance, massively parallel computing systems.
The models show excellent agreement with published analytical solutions for a broad range of rock and fluid properties and fracturing conditions. The models also show reasonable agreement with laboratory experiments for a similar range of conditions. The models scale up from lab to well scales and have shown practical applicability for a diverse set of challenging oil and gas problems.
Most hydraulic fracture models fall into the categories of fast-running but with simplified physics, or complex physics but computationally impractical for full-scale commercial applications. The models described in this paper have been applied at commercial time and length scales, but also provide for full representation of the complex physics of hydraulic fracturing, as demonstrated by the comprehensive validation with analytical solutions and laboratory experiments.
Srinivasan, Karthik (Schlumberger) | Krishnamurthy, Jayanth (Schlumberger) | Williams, Ryan (Schlumberger) | Dharwadkar, Pavan (Schlumberger) | Izykowski, Tyler (Schlumberger) | Moore, William Ray (Schlumberger)
Since the inception of the oil boom in North Dakota, the Williston basin has witnessed a tremendous growth in horizontal drilling and completion activity primarily targeting the Bakken and Three Forks formations. Although the activity in the basin is maturing in terms of our understanding rock quality and completion quality, there is a wide variation of these indices within the basin from one field to another. Some of these variations are clearly noticeable in parameters such as thicknesses of the shale barriers, pore pressure gradients, reservoir permeabilities, porosities and stress gradients. The combined impact of these parameters has a huge impact on key decisions including, but not limited to, completion methodologies, types of proppants and fluids used for completion, number of fracturing stages in the lateral, number of perforation clusters per stage, and well spacing.
This paper discusses the evolution of stimulation strategies and completion practices in the Williston basin since 2009. Operators have experimented with cemented and uncemented laterals; sliding sleeves and plug-and-perf completions; lateral lengths ranging from 5,000 to 10,000 ft; perforation clusters ranging from one to six per stage; crosslinked, hybrid, and slickwater fluid systems; proppants ranging from sand to ceramic, etc. The consequent impacts of these variations on well completion pressure responses and long-term production have been mixed. As part of the work covered in this paper, the differences between various completion methodologies and their impact on the stimulation strategies have been discussed in a chronological order.
Although there is no single optimized design for the entire basin, experimentation of multiple methods and technical interpretation of various fracture and production models have provided us with a strong foundation to narrow down our practices to the most successful and repeatable ones across all the fields in the Bakken and Three Forks formations. The paper also covers how real-field measurements such as diagnostic fracture injection tests (DFITs), microseismic data, radioactive or chemical tracers, bottomhole pressure gauges, and interference experiments combined with log measurements such as magnetic resonance, acoustic logs, and elemental spectroscopy can provide us with a strong base for building and calibrating reservoir models that are reliable and reasonable.
The paper covers technical differences between sliding sleeves and plug-and-perf completions; differences between crosslinked, slickwater, and hybrid designs and their impact on fracture geometries; effect of using different proppant types; and ways to optimize the number of fracturing stages and proppant and fluid volumes. As part of the study, the importance of geomechanics in understanding planar versus complex fracture geometries is discussed to close the loop with reservoir simulation models.
Enhancing complexity of the created fracture geometry is the primary challenge for hydraulic fracturing treatment design in shale formations because of their stress anisotropy. Therefore, near-wellbore diversion is required to evenly stimulate all perforated clusters while far-field diversion inside the created fracture induces additional branch fracturing by overcoming the stresses holding the natural fractures closed. Solid particles with different shapes and sizes are widely used as diverting agents during fracture treatments. The recommended particles should temporarily bridge inside the fracture to create a low- permeability pack that increases the pressure within the fracture and enables redirection of next-stage fluid to understimulated intervals.
The objective of this study is to experimentally investigate and optimize parameters affecting the selection of solid particles as diversion agents such as material chemistry, particle size, particle shape, particle size distribution, particle loading, carrier fluid type, and carrier fluid viscosity. Three tests were performed in this study: Bridging tests to determine the optimized particle size and loading as function of fracture width (0.04 to 0.2 in.); pack permeability tests to optimize the particle size distribution and shape needed to minimize fracture conductivity and build the needed pressure; and dynamic dissolution tests to determine the time need to completely dissolve the particles as function of temperature, rate, particle size, and produced fluid.
The results of this paper can help in understanding the diversion parameters required to effectively enhance the complexity of the fracturing geometry. For far-field diversion applications (targeting fracture widths of 0.04 to 0.08 in.), larger particles are not required, as the fracture width is small. However, very tight particle pack permeability is needed. For near-wellbore and perforation diversion (targeting fracture widths of 0.2 in. and higher), only larger particles can bridge the wider fractures. Therefore, a wider (in this case tri-modal) particle size distribution is required: coarse particles to bridge the fracture along with a bi-modal distribution of medium and small particles to minimize the particle pack permeability and achieve the diversion. A diverter pack with bi-modal size distribution and higher concentration of small particles reduces particle pack permeability more than a tri-modal size distribution with more medium-size particles. Diverter A and B tested in this study were able to bridge inside the fracture, reducing its conductivity by converting the open width into a porous medium with a tight permeability for both applications: far-field and near-wellbore. Diverter A (NW) is more efficient and effective than commodity benzoic acid flakes for a simulated near-wellbore application with a fracture width of 0.2 in. The diverter pack dissolved more slowly in slickwater fluid than in DI water, probably more due to the slickwater's polymer content than its minimal increase in viscosity.
Ramurthy, Muthukumarappan (Halliburton) | Richardson, Joe (Bayswater Exploration & Production LLC) | Brown, Mark (Bayswater Exploration & Production LLC) | Sahdev, Neha (Halliburton) | Wiener, Jack (Halliburton) | Garcia, Mariano (Halliburton)
Hydrocarbon production has been long existent in the Denver Julesburg basin and with the development of horizontal drilling technology the Niobrara has become one of the most economical plays even with lower oil prices. The multi-bench Niobrara formation is the primary target in the basin followed by the Codell. Even with the better economics, the Niobrara and the Codell completions are not optimized yet. The operators are still aiming for more and more stages with lesser spacing thus increasing the costs. The objective of this study is to show that stage spacing can be optimized with low cost diversion technology yielding equal or better production with fewer stages thus lowering costs.
In this optimization study, two Niobrara "C" bench lateral wells from the same pad that are next to each other were selected as candidates. The first well, Well-K was completed with 28 stages geometrically spaced at 153 feet utilizing the perf-n-plug methodology. The second well, Well-L was completed with 20 stages, geometrically spaced at 215 feet, also utilizing the perf-n-plug methodology. Well-L was stimulated utilizing the intra-stage diversion process and had approximately 404,000 lbm less proppant than Well-K. Well-K was completed without the diversion technology. Following stimulation and flowback, Fibercoil with Distributed Temperature Survey (DTS) and Distributed Acoustic Survey (DAS) capabilities were run in both the wells to diagnose the contribution from each perforation cluster. The Fibercoil results clearly showed that Well-L with larger stage spacing and intra-stage diversion had 80% fracture initiation as opposed to 60% with the limited-entry Well-K that had shorter stage spacing. The production results so far are very encouraging for the L-well. The 180-day cumulative oil production for Well-L is almost similar to Well-K with the normalized barrels of equivalent oil (BOE) per foot, BOE/ft. difference being lower by 3%.
This study has clearly shown us that with some additional enhancement intra-stage diversion can be used to optimize stage spacing without compromising production. The post-frac fracture modeling analysis along with the Fibercoil results including warm-back analysis and production for the two wells is presented.
With the large number of fracture stages, and size of jobs being pumped in horizontal wells, many companies have elected to use non-standard, or non-commercial natural sands as propping agents. The Stim-Lab Proppant Conductivity Consortium, supported by approximately 50 proppant suppliers, pumping service companies and operators, has developed consistent laboratory conductivity test procedures over the past 30 years that have become de-facto industry standards. One outcome of this long history of proppant testing is a set of correlations that can predict the baseline conductivity, as a function of closure stress and rock (substrate) properties, within the range of uncertainty of laboratory tests. Inputs to the correlations are basic material property measurements such as specific gravity and median particle size of the sieve distribution. The correlations can be used to compare materials of unknown properties to standardized data sets, or to develop useful predictions of how a non-standard material is likely to perform. The correlations are general enough for application to brown sand, white sand, resin-coated materials, and ceramic proppants of various sizes and densities. These correlations have been found to be sufficient for comparing proppants and for estimating their performance in production computations, when adjustments for appropriate damage and cleanup are made to the calculated baseline conductivity values.
A modeling framework is developed to describe proppant transport (including gravitational settling and tip-screen out) in a hydraulic fracturing simulator that can function as either fully-3D or pseudo-3D. The simulator locally enforces mass balance of fluid and proppant and applies appropriate boundary conditions for mechanical calculations. The simulator uses recently developed constitutive equations that smoothly capture the transition from Poiseuille flow to Darcy flow as the proppant concentration transitions from a dilute mixture to a packed bed. We develop new constitutive relations that enable the model to describe fracture closure against proppant (at either low or high concentration) after the end of injection. We also develop a framework for modeling proppant settling in a pseudo-3D model. The method ensures a continuous solution, which guarantees convergence and accuracy with refinement of the temporal and spatial discretization. The framework allows proppant to settle into a proppant bank at the bottom of the fracture. The proppant bank can grow, remain stationary, or erode, depending on flow conditions. The simulator can describe tip-screen out (TSO) and the tendency for the volumetric flowing fraction of proppant to exceed the volumetric fraction of proppant due to the tendency of proppant to flow at the center of the fracture aperture. Pseudo-3D simulations are compared to the fully-3D simulations for both hydraulic fracturing and long-term production. For hydraulic fracturing, the pseudo-3D simulations are able to substantially reproduce the results from the fully-3D simulations and are far more computationally efficient. The simulation methods are compared using a variety of values for proppant size, fluid viscosity, and proppant density. An optimized proppant schedule is tested in order to improve horizontal proppant placement and prevent excessive tip screen-out. The simulations indicate that because fracture closure can be slow in very low permeability formations, substantial settling occurs after the end of injection, significantly worsening vertical proppant placement. For simulation of long-term production, the pseudo-3D results deviate strongly from the fully-3D simulations, indicating that the pseudo-3D model is not suitable for simulating the production phase, as currently formulated.
The objective of achieving uniform stimulation of a reservoir through hydraulic fracturing from a horizontal well typically depends upon the ability to generate a uniform array of hydraulic fractures from multiple entry points. However getting all the hydraulic fractures in an array to grow simultaneously is a challenge. The challenge apparently arises not only due to reservoir variability, but also in a substantial part due to the stress interaction among growing hydraulic fractures. This phenomenon, referred to as a stress shadowing, inhibits the growth of inner fractures and favors the growth of outer fractures in the array. Recently, we created a new hydraulic fracture simulator which simulates the growth of an array of hydraulic fractures in 10-6–10-5 of the computation time required for fully coupled 3D simulations of multiple parallel planar hydraulic fracture growth. Using a novel energetic approach to account for the coupling among the hydraulic fractures and through judicious use of asymptotic approximate solutions, the simulation enables designs reducing the negative effects of stress shadow by balancing the interaction stresses through non-uniform perforation cluster spacings. Furthermore, so-called limited entry approaches are thought to be capable of promoting greater uniformity among simultaneously growing hydraulic fractures as long as the number and diameters of the perforations in each cluster are appropriately designed. In order to enable such optimizations and designs, we add perforation loss into to the approximate, energy-based simulator. Our results show the potential of choosing the proper perforation diameter and number to double the fracture surface area generated by a given injected fluid volume though minimizing the negative effect of interaction. The usefulness of the new simulator is demonstrated by development of example limited entry designs and optimal spacings for different numbers of entry points.
Laminated structures in shale formations typically result in anisotropic elastic properties, including Young's modulus and the Poisson ratio, which highly influence hydraulic fracturing treatment execution. The lamina can confine the hydraulic fracture height growth and they sometimes act as weak interfaces for potential fracture propagation path. Hydraulic fracture geometries are highly affected by these properties. In order to make more accurate prediction of hydraulic fracture pattern, especially fracture height, these factors cannot be ignored.
We utilized a recently developed Finite Element-Discrete Element Method (FEDEM) code to simulate the complex fracture propagation in shale formations. This coupled fluid flow and geomechanics simulation can also models multi-fracture, multi well fracture propagation scenarios. For simulating fracture height growth, the bedding planes module (with corresponding mechanical anisotropy properties generation) are incorporated. Both 2D and 3D hydraulic fracture propagation studies can be performed.
Our simulation results show that without considering the mechanical anisotropy effect, the treatment design will be corrupted by the inaccurate prediction of fracture height. To be more specific, in typical mechanical anisotropic formation, fracture height is always smaller than the fracture height in mechanical isotropic formation, and the fracture tends to propagate (at least temporarily) along the bedding plane interfaces. Different bedding plane properties, including bedding plane dipping angle, permeability etc., also have strong influence on the predicted fracture height. We also consider fracture height growth in multi fracture schemes. The stress shadowing effects give rise to non-planar vertical growth and possible fracture branching. The simulations show that hydraulic fracture height growth is substantially restricted in laminated formations.
This paper provides a framework for more realistic prediction of fracture height and fracture pattern evolution in laminated shale formations exhibiting mechanical anisotropy.
Morales, Adrian (Schlumberger) | Zhang, Ke (Stanford University) | Gakhar, Kush (Schlumberger) | Marongiu Porcu, Matteo (Schlumberger) | Lee, Don (Schlumberger) | Shan, Dan (Schlumberger) | Malpani, Raj (Schlumberger) | Pope, Tim (Schlumberger) | Sobernheim, David (Schlumberger) | Acock, Andrew (Schlumberger)
This paper continues the investigation of interwell fracturing interference for an infill drilling scenario synthetic case based on Eagle Ford available public data and explores pressure and stress-sink mitigation strategies applied to the simulation cases developed in the previous publication (SPE 174902). Emphasis is given to refracturing scenarios, given the intrinsic restimulation value for depleted parent wells and the strategic importance due to the current low oil prices.
The stress and pressure depletion methodology is expanded in this paper, adding a refracturing scenario before the infill child well is stimulated. Changes in stress magnitudes and azimuths caused by new and reactivated fractures are calculated using a finite element model (FEM). After refracturing the parent well, modeling shows that stress deflection and repressurization of the originally depleted production zone will reduce subsequent fracture hits from infill wells.
The first mechanism to reduce fracture hits is the stress realignment, which promotes transverse fracture propagation from the infill well away from the parent well. The second fracture-hit-reduction mechanism is repressurization of depleted zones to hinder fracture propagation in lower-pressure zones. Prevention of fracture hits by active deflection results in an increased stimulated reservoir volume (SRV) for both the parent and child wells. Overall pad level and individual wellbore cumulative production experience a significant increase due to increased SRV. With proper reservoir and geomechanical data, this approach can be applied in a predictive manner to decrease fracture-hit risk and improve overall recovery.
This workflow represents the first comprehensive multidisciplinary approach to coupling geomechanical, complex hydraulic fracture models, and multiwell production simulation models aimed towards understanding fracture-hit reduction using refracturing. The workflow presented can be applied to study and design an optimum refracturing job to prevent potentially catastrophic fracture hits during refracturing operations.
Refracturing in the US midcontinent is not a new method. In 1980, a refracturing program was begun in the shallow, low-pressure Brown Dolomite gas pay in the Texas panhandle. The results were mixed, but the overall outcome was economically beneficial. Currently, operators are refracturing horizontal shale wells, especially those completed from 2003 to 2010. However, results continue to be mixed and unpredictable. This paper presents lessons learned during refracturing treatments performed between 1980 and the present that led to the creation of a new approach to refracturing treatments.
This paper discusses the factors to consider when planning a refracturing program. Refracturing failures are also discussed as a means to understand the controllable and uncontrollable variables that lead to these failures. Failures are categorized and specific failure types and modes are identified. Examples of successful refracturing treatments are also included.
The resulting newly developed refracturing approach includes a four-step process:
Candidate identification Refracture diversion design Execution and diagnostics Production analysis and diagnostics
Refracture diversion design
Execution and diagnostics
Production analysis and diagnostics
Examples of using the four-step process are provided to show the incremental improvements that resulted from identifying potential candidates and designing, executing, and analyzing the project. Production results and incremental estimated ultimate recovery (EUR) values are discussed to illustrate the economic viability of refracturing, and the economic benefit of this incremental production increase is compared with the cost of the refracturing treatment. While incremental production from refracturing in the midcontinent has more than doubled, pre- and post-fracture diagnostics should improve the success rate by defining lateral coverage. Real-time diagnostic techniques are discussed as potential tools for pre- and post-refracturing analysis.
Despite the history of mixed results, refracturing efforts are improving through the implementation of this new four-step approach. Repressurization of the original fracture system is common to successful refracturing throughout time. New diversion materials and placement processes help achieve repressurization and refracturing placement success. Also, additional insight from new diagnostic tools and techniques can help improve the overall refracturing project success.