bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimum Production Metrics to Predict Unconventional Well's Long-term Performance
Authors: Ifejika Edward , De Cumont Bertrand , Kashani Nommie 
Published: January 2017

Abstract
In a challenging price environment, developing unconventional plays requires a relentless effort at improving operations practices. However, comparing the impact of different completion designs or well management strategies on well performance remains a challenge due to these plays relatively brief production history and lack of long-term field analogs. This study examines various production durations as potential candidates for reliable indicators of well quality. A reservoir modeling approach for unconventional plays is time consuming and may not properly simulate the complex interaction between subsurface properties and operational strategy. Assessment based on early production may be misleading due to well clean–up issue while comparison based on long-term well performance is inappropriate for quick decision making. This is an approach to find an optimum production duration for performance indicator, early enough to be useful and late enough not to be impacted by wells’ clean-ups. The workflow was developed then tested on Utica Shale unconventional play in Ohio, USA, and using data from 676 producing wells. The results show that predictions of midterm performance start to be reliable only near 180 days of cumulative well production. This study used actual daily production data to confirm that IP-30 days and IP-90 days are not strongly correlated to well actual performance in two year range. It also gives validation for the concept of use of 180-days to 360-days performance as more reliable indicators of well quality. The identification of a reliable quality indicator is a critical first component for any subsequent analysis attempting to identify the underlying factor controlling productivity. This study illustrates the danger inherent in the commonly used industry practice of quantifying well quality based on early production. In particular it shows that the first 30 days of production has almost no correlation with longer term production life.
Analysis of Front and Tail Stress Shadowing in Horizontal Well Fracturing: Their Consequences With Case History
Authors: Daneshy Ali 
Published: January 2017

Abstract
Creating multiple hydraulic fractures and keeping them open with proppant deforms the formation in their surroundings. These deformations generate normal and shear stresses within the formation, defined as stress shadowing by the oil and gas industry. Front stress shadowing denotes the effect of these stresses on future fractures. Tail stress shadowing defines their effect on previously created fractures. Front shadowing causes a gradual increase in the fracturing pressure of subsequent stages, ISIP, and deviation in fracture growth path. Tail shadowing accelerates fracture closure and also reduces the intensity of front shadowing.
Existing analyses of stress shadowing consider only front shadowing and are generally based on numerical techniques with assumed fracture growth models, and varying approximations of the closing/closed fracture width. This paper uses a rigorous analytical approach to compute the effects of stress shadowing at different stages of fracture closure, and its effect on the pressure and orientation of subsequent fractures. As in actual field situations, the analysis allows for each of the previous fractures to be in different partial closure state. It shows that the stress shadow created by each stage of fracturing extends for only a limited distance ahead and behind it. When the cumulative effects of multiple fracture stages and their progressive closures are examined, the result is a gradual increase in fracturing pressure and ISIP during the early stages, followed by relatively constant values thereafter. Although stress shadowing can cause sharp local deflections in the fracture path, even in extreme cases the angle of deflection decreases along the length of the active fracture. Thus stress shadowing is unlikely to cause fracture coalescence in and by itself. Another effect of fracture deflection is to reduce the effect of stress shadowing in the later stages of fracturing.
The main consequences of tail shadowing are accelerating closure of previous fractures, and reducing the intensity of front shadowing by transferring more of the induced deformation behind each fracture. Fracture deflection caused by stress shadowing is largest when the two horizontal principal stresses are very close to each other. Another factor that influences stress shadowing is the time lapse between stages. Longer lapses reduce the magnitude and effect of front stress shadowing.
Results of this analysis are compared with field data, with reasonable agreement. They show that the effect of stress shadowing is not as large as generally assumed by the fracturing community. Paper includes practical recommendations to help detect the presence and magnitude of front stress shadowing in fracturing data.
Calculating the Volume of Reservoir Investigated During a Fracture-Injection/Falloff Test DFIT
Authors: Craig David P. , Jackson Robert A. 
Published: January 2017

Abstract
Unconventional reservoirs, including shale formations and many tight-gas sands, contain natural fractures, fissures, faults, and microfractures that contribute to the rock flow capacity; thus, core-measured permeability, and especially crushed-core permeability measurements, may not be representative of the true reservoir rock flow capacity. Evaluating the in-situ rock permeability, and simulating production, requires sampling not only the matrix, but also the fractures and fissures that contribute to the unconventional rock system permeability. A properly designed well test in an unconventional reservoir will sample a volume of reservoir rock that is representative of the whole. In other words, a well test should sample a representative elementary volume, which is the smallest volume of rock with properties characteristic of the whole.
Diagnostic fracture-injection/falloff tests (DFIT) have been routinely implemented since the late 1990s to understand leakoff mechanisms, identify fracture closure stress, estimate initial reservoir pressure, and determine permeability-thickness in unconventional reservoirs. In almost every unconventional well completed, a DFIT is the only well test that will be completed during the well lifecycle, but historically, the tests have been designed empirically based on analog formations and without considering the volume of rock investigated.
We demonstrate a new method for calculating the volume of rock investigated by a DFIT, and we show how a DFIT design can allow for sampling a representative elementary volume of the reservoir.
From the Backyard Dune to Fracturing a Highly Tectonically Complex Formation in Saudi Arabia
Authors: Bartko K. M. , Arnaout I. H , Asiri K. S. , McClelland K. M. , Mulhim N. I. , Tineo R. , Gurmen M. N. , Al-Jalal Z. , Pantsurkin D. , Emelyanov D. Y. 
Published: January 2017

Abstract
Sand in Saudi Arabia is easily accessible through surface mining or excavating large dunes that are API approved, but like many sands around the world, lacks the necessary strength for fracturing high stress formations. To exploit the sand, a novel engineered workflow, enabled by the flow channel fracturing technique was established for qualifying and implementing Saudi Arabian sand to fracture stimulate the tectonically complex ultra-tight "T" carbonate formation.
Channel fracturing does not depend on the proppant pack to provide conductivity, rather on the creation of stable, open flow channels. Therefore, carefully selected sand that can keep the channel structure open under stress can be a viable material to replace up to 80% of the ceramic proppant materials. The local sand used was qualified through unique lab testing procedures to understand the pack behavior under stress, the pillar erosion under stress, and the effects of stress on long-term conductivity. Once qualified, a design methodology was applied to optimize the fracture geometry and pillar placement for the initial field test in Well-A, a horizontal lateral where high strength proppant (HSP) is traditionally used.
A total of six channel fracturing stages with local sand — 40% of the total stages — were placed as per design in two sections of the 15-stage lateral along with four conventional and five channel fracture stages using HSP. A multi-month cleanup and well test period resulted in Well-A being one of the best producing wells in the basin — 26% higher initial production than the next best well. A production log showed sand stages to be producing an average of 15% higher total production than HSP stages. An oil tracer analysis revealed sand stages produced an average of 62% more condensate than HSP stages. This initial production response confirms at least par production with no detrimental effects for channel fracturing with local sand compared to techniques using HSP, with the potential for improved production.
This qualified and field tested completion methodology allows for the potential replacement of a significant portion of imported ceramic proppant with locally sourced sand, an abundant and accessible resource inside the Kingdom of Saudi Arabia and beyond. The benefits of this technology include cost reduction, placement improvement, at least par production and the maximizing of in-country content and value.
Observations and Modeling of the Relation Between Effective Reservoir Stress and Hydraulic Fracture Propagation Pressure
Authors: Pater C. J. , Prabhakaran R. , Shaoul J. R. 
Published: January 2017

Abstract
Accurate prediction of net hydraulic fracture propagation pressure is often impossible. Under some conditions the pressure drop along the fracture dominates while in other cases the pressure at the tip determines the net pressure. Properly scaled lab tests and modeling indicate that effective stress determines the tip propagation pressure, but this is hard to confirm with field data in specific cases.
We therefore gathered a large data base of fracture treatments from many areas to investigate the correlation between net pressure and effective stress. In order to avoid any spurious effect from fluid friction, tortuosity and height containment we limited the data to relatively small injections with water or linear gel in vertical wells. All treatments were in conventional clastic reservoirs, but over a large range of permeability, rock stiffness and geological age.
The data show a remarkably good correlation between net pressure and effective reservoir stress, with a slope of 0.46. Lower net pressure of 200-300 psi was found in over pressured reservoirs and higher net pressure of about 1500 psi was seen in depleted reservoirs. We checked that this is not due to another underlying parameter, such as modulus or depth, which could explain the correlation. It is concluded that the correlation is due to a true relation between net pressure (controlled by fracture propagation) and effective stress. Simulation of representative treatments with a new model that includes a cohesive zone at the fracture tip shows excellent agreement with the observed correlation, supporting a physical relation.
The relation between net pressure and effective stress in the reservoir can contribute to improved treatment design in green fields and also will aid in understanding fracture height growth, since effective stress will differ between formation layers. Calibrated models will still be important in view of lack of detailed formation knowledge, but a correct description of the physics of fracture propagation, based on effective stress at the tip, will facilitate more accurate model predictions.
Reservoir and Completion Considerations for the Refracturing of Horizontal Wells
Authors: Barree R. D. , Miskimins J. L. , Svatek K. J. 
Published: January 2017

Abstract
Horizontal well developments, focused on transverse hydraulic fracture stimulation, have evolved rapidly over the past decade. Many of these completions may have missed or bypassed significant reserves that were intended to be produced from the well. This paper discusses the potential reasons for these inefficient completions, candidate selection for refracturing, and the impacts of offset depletion/infill wells on refracturing.
Rate transient post-treatment stimulation analysis is a powerful tool that can help to determine if and when a horizontal well is receptive to refracturing. Such analysis can help to determine if a well is underperforming, and if that underperformance is due to an inefficient completion or due to reservoir conditions. The paper discusses the importance of appropriate well conditioning/unloading prior to determining if a refracturing may or may not be successful. The impacts of "bashing" into offset depletion during refracturing treatments is also discussed, along with appropriate design considerations to minimize such impacts.
Refracturing can be an important tool to the industry and deserves the attention that it is currently receiving. However, success of such treatments is not guaranteed in every well and the criteria for candidate selection should be a top focus when evaluating such a program.
Comparison of Multi-Stage Fracture Placement Methods for Economic Learning and Unconventional Completion Optimization: A Case History
Authors: Singh Amit , Soriano Lori , Lal Manish K. 
Published: January 2017

Abstract
The two most popular fracture placement methods in unconventional shale with multiple stages fracturing completion are wireline plug-n-perf and pinpoint perforating / fracturing using coiled tubing. The debate regarding which method is better is still unresolved, as each method has its performance and economic advantages, which make the selection decision very challenging for practitioners and decision makers.
In the Antelope Shale reservoir in Monterey Formation, each of these two fracture placement methods were implemented for multi-stage fracturing in 4 vertical offset wells to evaluate the benefits and associated risks, and to identify the preferred method for a full field development plan. The plug-n-perf method had multiple clusters perforated with wireline for each frac stage, whereas the coil tubing method utilized sand-jets to create pinpoint perforation holes with single cluster.
In this paper, we discuss the lessons learned and results from application of both fracture placement methods in Antelope Shale using key performance and economic indicators, including time efficiency, cost, production, fracture geometry and zonal coverage. The multitude of operational events experienced during these completion executions demonstrated both the associated benefits related to improved efficiency (efficient completion execution without trouble, record number of completions in single day, etc.) and disadvantages in terms of delayed operation (perforation guns not firing, CT parting, multiple fishing operations during drill out of plugs, ineffective perforation cutting, depth control of CT, etc). The results from various diagnostics such as microseismic, tiltmeters, Diagnostic Fracture Injection Test (DFIT), tracers, etc. were used to compare the effective pay zone coverage with multiple fracture stages, fracture geometry and well productivity for both fracture placement methods.
For multi-stage fracturing completions in tight rock, an understanding of risks, rewards, and economic impact of both methods is crucial to completion and stimulation strategy.
A Fully-Coupled, Poro-Elasto-Plastic, 3-D Model for Frac-Pack Treatments in Poorly Consolidated Sands
Authors: Lee Dongkeun , Sharma Mukul M. 
Published: January 2017

Abstract
Frac-pack completions have been used as a technique for well stimulation and sand control. Conventional hydraulic fracturing models based on linear elastic fracture mechanics often lead to inaccurate predictions of fracture geometry and fracturing pressure response due to large inelastic deformations and strong fluid-solid coupling. We present a fully-coupled, three-dimensional hydraulic fracture model in poro-elasto-plastic materials using a finite volume cohesive zone model for frac-pack applications.
Our model is capable of capturing the high net fracturing pressure commonly observed during frac-packing operations. The 3-D model simulates both shear and tensile failure around the fracture and computes the stresses and displacements around the fracture. We observe that plasticity causes lower stress concentration around the fracture tip which shields the tip of the propagating fracture from the fracturing pressure. High leak-off can also lead to shear failure around the fracture and ahead of the tip due to pore pressure diffusion. The low cohesion sands tend to fail in shear first then in tension if sufficient pore pressure and poroelastic backstress build up. We use a three-dimensional numerical computation of fluid leak-off using a fracture-reservoir domain coupling in this model to overcome the limitation of linear, one-dimensional leak-off models. Higher pressure gradients due to lower permeability, higher viscosity and injection rate results in a faster fracture propagation rate.
LEFM models inherently predict lower net fracturing pressure, smaller fracture widths and longer lengths in soft formations than observed in the field. In many instances, such models are used to fit the net pressure data by manipulating input parameters beyond physically reasonable values. The model presented here provides a much more physically realistic approach to model fracture growth in unconsolidated reservoirs with lab measured mechanical properties. The model has allowed us to design and analyze hydraulic fracturing stimulations much more accurately than LEFM models used in the past.
Elliptical Flow Regimes in Horizontal Wells with Multiple Hydraulic Fractures
Authors: Apte S. S , Lee W. J 
Published: January 2017

Abstract
The paper demonstrates that the transient flow regime in multi-fractured horizontal wells, often interpreted as linear flow, is more likely elliptical flow. Elliptical flow often cannot be distinguished from linear flow at earliest times, but the apparent transition between transient linear flow and boundary-dominated flow may, in fact, be strongly affected by elliptical flow prior to being influenced by interference between adjacent fractures. Taking the elliptical flow regime into account can often improve our interpretation of production histories and our ability to forecast future production, thus improving economic evaluation and reserves estimation.
We verified elliptical flow regimes by comparing production forecasts from existing semi-analytical and analytical solutions for multi-fractured horizontal wells. We then used asymptotic approximations to elliptical flow solutions to identify important flow regimes and to validate our model.
On the basis of this work, we proposed new methods to determine reservoir properties and explored the parameters influencing the productivity of a multi-fractured horizontal well in a tight shale formation. Finally, we demonstrated, with a field example, the utility and applicability of our elliptical models and work flows for data analysis based on them.
We emphasize our conclusion that transient linear models appear to be mere approximations of the more complete elliptical models during early flow periods in multi-fractured horizontal wells and thus open a question for debate: Is transient linear flow a myth (a mere approximation) or a real flow regime?
Impairment of Fracture Conductivity in the Eagle Ford Shale Formation
Authors: Guerra Jesse , Zhu D. , Hill A. D. 
Published: January 2017

Abstract
Fracture conductivity in shale formations can be greatly reduced due to water-rock interactions. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration due to fracture surface spalling and failed proppant particles. Fracture conductivity is influenced by closure stress, bulk and surface rock mechanical properties, fracture surface topography, fracture surface elemental composition, rock mineralogy, proppant type and concentration, among other factors. This paper presents a study considering several of the aforementioned factors, centered primarily on saline water induced fracture conductivity impairment of the Eagle Ford shale formation and its five vertical lithostratigraphic units.
Laboratory experiments were conducted to investigate the effect of flowback water on fracture conductivity for Eagle Ford shale samples. The majority of test samples were obtained from an outcrop located in Antonio Creek, Terrell County, Texas; while the remaining samples were obtained from downhole core provided by an industry partner. Saline water with a similar chemical composition to the typical field flowback water was utilized.
Fracture conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady state behavior was observed. In the third and final stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop rock samples, consisting of Poisson's ratio and the Brinell hardness number, were considered in this study. Additionally, reported mineralogy obtained using X-ray powder diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained using X-ray fluorescence (XRF) microscopy, and fracture surface topography was obtained using a laser surface scanner and profilometer.
Results support findings that bulk and surface mechanical properties influence fracture conductivity, as well as surface topography and related attributes such as fracture surface area. Furthermore, the bulk mineralogical composition of the rock and the elemental composition of the rock fracture surface have a significant impact on fracture conductivity when flowing saline water in order to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for Eagle Ford formation ranging from approximately 4 to 25 % after flowing saline water, when compared to the initial conductivity measured by flowing dry nitrogen before saline water exposure. This is not a large loss in conductivity due to water damage, and suggests that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford shale producing wells.