bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Ash Beds on Production in Eagle Ford Shale
Authors: Xu Jian , Fisher Kevin , Qiu Fangda , Malpani Raj , Ejofodomi Efe , Viswanathan Anup 
Published: January 2016

Abstract
The Eagle Ford shale contains both kaolinite- and smectite-rich altered ash beds that present challenges for completion and production. Considering the five Eagle Ford units (A–E), the ash beds occur in the B unit. The B unit is divided into five subunits; B1 and B2 are characterized by the highest total organic carbon (TOC) whereas B3–B5 have a higher frequency of ash beds. The impact of these ash beds is not yet fully understood, but acquired horizontal production log measurements indicate that the production performance of stages landed in the B3–B5 units, with high ash bed frequencies, are poor compared to other stages landed in a different unit. Some operators are vertically staggering laterals to effectively drain the reservoirs, partially due to the lack of vertical connection in the production phase. Thus, to increase the effectiveness of the completion strategy and ultimately the well performance, methods must be developed to quantify the impact of ash beds on production and to mitigate the negative impact. An integrated hydraulic fracture-reservoir modeling workflow was applied on an Eagle Ford shale lateral with part of the lateral crossing an ash bed in B3–B5 units. The subject well was completed with 15 stages. The simulation results demonstrate that the ash beds in B3–B5 units restrict part of the created hydraulic fracture height and create conductivity pinch points, thus reducing the effective fracture height connected to the wellbore. This, in turn, affects the potential well productivity. Based on the simulated results, the optimum lateral landing location is within the B1–B2 interval. The analysis also showed that targeting the hydrocarbons in these units requires a different completion strategy. Use of a crosslinked fluid carrying higher proppant concentrations will facilitate the creation of larger fracture widths to withstand the negative impact of the ash beds isolating a certain portion of the created fracture height.
Understanding the Applicability and Economic Viability of Refracturing Horizontal Wells in Unconventional Plays
Authors: Lindsay G. J. , White D. J. , Miller G. A. , Baihly J. D. , Sinosic B. 
Published: January 2016

Abstract
Oil prices have fallen to lows not seen in years. These low oil prices and sustained low gas prices have drastically reduced the number of new wells being drilled in US unconventional plays as oversupply from these plays has reached an all-time high in US storage levels. One alternative to drilling new wells is to hydraulically refracture older wells to enhance production and gain additional economic returns. With each successful refracturing operation, service companies are improving on methods to divert refracturing fluid and proppant without the use of mechanical diversion techniques. To ensure success and meet economic hurdles, refracturing requires thorough preparation, proper candidate selection, and effective diversion techniques.
The authors of this paper studied the economic potential and applicability of refracturing in six different unconventional plays across the US, including the Haynesville, Fayetteville, Barnett, Woodford, Eagle Ford, and Bakken plays. The expected rates of return for refracturing were compared to the economics of new wells to determine which alternative is a better use of capital spending and how the economics vary by play. Major challenges with refracturing horizontal laterals are highlighted, along with criteria for picking the best refracturing candidates to reduce risk and help meet economic hurdles.
We carefully searched through over 20,000 laterals completed since the second half of 2013 in the US and found more than 100 horizontal wells refractured by chemical diversion means based on public records. The production results of these wells were evaluated to identify the best basins for economic success. The Haynesville and Eagle Ford show the best rates of return, whereas other basins will require higher market prices, changes to current refracturing techniques, and/or identification of the best refracturing candidates to minimize the associated risks. The number of economic horizontal refracture candidates across the various basins will vary with fluctuations in oil and gas prices.
Strategies for Effective Stimulation of Multiple Perforation Clusters in Horizontal Wells
Authors: Manchanda Ripudaman , Bryant Eric C. , Bhardwaj Prateek , Sharma Mukul M. 
Published: January 2016

Abstract
Increasing the efficiency of completions in horizontal wells is an important concern in the oil and gas industry. To decrease the number of fracturing stages per well it is common practice to use multiple clusters per stage. This is done with the hope that most of the clusters in the stage will be effectively stimulated. Diagnostic evidence, however, suggests that in many cases only 1 or 2 clusters out of 4 or 5 clusters in a stage are effectively stimulated.
In this paper strategies to maximize the number of effectively stimulated perforation clusters are discussed. A fully 3-D poroelastic model that simulates the propagation of non-planar fractures in heterogeneous media is developed and used to model the propagation of multiple competing, fractures. A parametric study is first conducted to show how important fracture design variables such as limited entry perforations and cluster spacing; and formation parameters such as permeability, lateral and verical heterogeneity affect the growth of competing fractures. The effect of stress shadowing due to both mechanical and poroelastic effects is accounted for.
3-D numerical simulations have been performed to show the impact of some operational and reservoir parameters on simultaneous competitive fracture propagation. It was found that an increase in stage spacing decreases the stress interference between propagating fractures and increases the number of propagating fractures in a stage. It was also found that an increase in reservoir permeability can decrease the stress interference between propagating fractures because of poro-elastic stress changes. A modest (about 25%) variability in reservoir mechanical properties along the wellbore is shown to be enough to alter the number of fractures created in a hydraulic fracturing stage and mask the effects of stress shadowing. Inter-stage fracture simulations show post-shutin fracture extension induced by stress interference from adjacent propagating fractures. The impact of poro-elasticity is highlighted for infill well fracture design and preferential fracture propagation towards depleted regions is clearly observed in multi-well pad fracture simulations.
The results in this paper attempt to provide practitioners with a better understanding of multi-cluster fracturing dynamics. Based on these findings recommendations are made on how best to design fracture treatments that will not only lead to the successful placement of fluid and proppant in a single fracture, but in a set of fractures that are competing with each other for growth. The ability to successfully stimulate all perforation clusters is shown to be a function of key fracture design parameters.
First Application for a Sequenced Fracturing Technique to Divert Fractures in a Vertical Open Hole Completion: Case Study from Saudi Arabia
Authors: Bartko Kirk , Tineo Roberto , Aidagulov Gallyam , Al-Jalal Ziad , Boucher Andrew 
Published: January 2016

Abstract
A unique sequenced fracturing technique using formation notching and degradable diversion pills was applied for the first time in a vertical open hole completion to stimulate multiple pay intervals in a well in the "Q" sandstone formation of Saudi Arabia.
The challenge to divert fractures in a vertical open hole is made more difficult by the large fracture surface area in contact with the wellbore. A robust, efficient and repeatable two-step technique was implemented to provide the diversion and controlled breakdown of higher-stressed sections of the interval. The first step used a specialized jetting nozzle to create circular notches and weaken the formation at target depths. The second step involved the pumping of a small volume of a composite fluid of degradable non-damaging fiber and particles that bridge at the fracture face, to divert the remainder of the treatment to under-stimulated sections of the interval.
The target for this well was a shallower formation due to completion pressure limitations while fracturing. This left six pay intervals spread across the tight, heterogeneous sandstone layers of the Q formation, which was completed as a single 552-ft. vertical open hole section. Previous experience showed large stress variations in the layers with contained fractures, and fracturing all pay intervals required separate treatments for each interval. After notching the pay intervals to reduce breakdown pressures, the interval was fractured with three proppant ramps separated by two diversion pills in the span of 8 hours, improving efficiency by more than three times. Diversion was confirmed by: (1) pressure increases of 380 psi and 500 psi, respectively, when the pills landed on formation; (2) increasing trend of the instantaneous shut-in pressures (ISIP's) throughout the treatment, resulting in 1,270 psi of net pressure gain; and (3) comparison of post-diagnostic injection test temperature log data with post-fracturing neutron log data, showing where nonradioactive traceable proppant was placed, including into at least three pay intervals not broken down during the injection test. Post-treatment production expectations were met and confirmed with a well test.
This paper will present the design, execution, and evaluation methodology and challenges overcome to divert hydraulic fractures in long vertical open hole intervals using this two-step diversion process for sequenced fracturing. The ability to do this consistently and predictably can provide a practical, efficient, and cost-effective preferred solution that does not exist today for completing and fracturing similar zones that are traditionally bypassed, resulting in increased production and reserves.
Improving North Sea Fracturing and Stimulation Economics Through Increasing Innovation and Efficiency in Operations and Applications: Lessons Learned
Authors: Ishteiwy O. , Doghmi A. , Rylance M. 
Published: January 2016

Abstract
Completion and intervention costs across the North Sea are at an all-time high and continue to challenge development economics; this has been exacerbated recently by a deteriorating oil price making cost-effective completion and intervention operations even more challenging. Typically at times such as these, the industry turns to the fracturing and stimulation process to maximise the return from existing assets and new wellbores. While this method continues to be feasible, increasingly this can only be achieved through challenging existing conventions and applying increasingly innovative approaches to the principal aspects and assumptions applied to the operations themselves; namely the deployment and the effectiveness of such operations in the field.
As the cost of a fracturing and stimulation execution mounts, due to numerous factors, including the efficiency of the service itself, available/economic well intervention capability, provision of sufficient accommodation (somewhat surprisingly/unhelpfully) and an ability to flow-back and clean-up in an efficient and effective manner. This paper will provide examples and case histories, across a number of our North Sea operations, which challenge and optimise each of these areas and demonstrate a number of mechanisms and approaches that have successfully been applied in order to reduce overall costs.
Some of the examples include a case history of the use of a boat (stimulation vessel) to boat (intervention vessel) stimulation approach, in order to eliminate secondary rig costs and thereby maximise the economics. Consideration of the use of a rig-based stimulation capability vs. extensive boat operations, efficient and cost effective well recompletion approaches and a suite of incremental improvements born out of continued North American solution development and deployment, such as the use of expandable packers and ball-drop matrix stimulations. Increasing the effectiveness of fracturing and stimulation (and maximising the productivity of each and every individual wellbore) is an obvious approach to improving economics and can be achieved in any number of ways. Again this paper will present a suite of examples and case histories of where this has already been achieved, across a number of our North Sea operations.
The current ‘perfect storm’, of a low oil-price environment combined with high industry contractual costs, is forcing all operators to become increasingly innovative in their pursuit of economic resource development across the North Sea. This paper presents a number of examples of innovation and cost-saving approaches that have been employed in order to achieve such economic intervention and provide further insight into the additional development potential and opportunity that may exist across this varied asset base.
Hydraulic Fracture Height Estimation in an Unconventional Vertical Well in the Vaca Muerta Formation, Neuquen Basin, Argentina
Authors: Ortiz Alberto César , Hryb Damián Emmanuel , Martínez Joaquín Ramirez , Varela Raúl Alejandro 
Published: January 2016

Abstract
One of the major uncertainties in the analysis of unconventional well productivity is the estimation of the hydraulic fracture height generated during stimulation operations. This study was carried out in a well located in the Neuquen Basin, Argentina with main focus on the development of unconventional shale oil.
The strategy consisted in the application of two combined techniques based on different and independent physical principles for the estimation of the hydraulic fracture height. The initial technique consisted in the pumping of proppant which contains elements with great neutron absorption. Thereby, the presence of traced proppant is identified through the differences in the neutron absorption capacity before and after the stimulation at approximately 6 inches from the wellbore.
The second technique is based on the characterization of the anisotropy on the shear wave obtained by the dipolar sonic curve in two perpendicular directions. This acquisition should be carried out before and after the stimulation and it is sensitive in the area close to the wellbore. (Between 5 and 40 in)
Results from both techniques showed a reasonable good consistency in the results, thus allowing the validation of both methodologies.
The results also allowed defining intervals that act as barriers of the hydraulic fracture vertical growth. This permit us the optimization of the fracture design in other wells, thus minimizing the vertical overlapping of the fractures and maximizing the connectivity of the stimulated interval in the well. In addition, traced proppant was confirmed close to the wellbore in several intervals that together represent approximately 60% of the pay which represents a 170 m. To improve completion efficiency, this information can be used to place hydraulic fracture stages and define clusters geometry.
Finally, it could be determined that a set of factors allowed the control of the vertical growth of the hydraulic fracture with proppant in the proximity of the wellbore. The main control on hydraulic fracture height was the magnitude of the minimum horizontal stress. The presence of discontinuities in the rocks such as calcite veins volcanoclastic intervals and limestone beds may also play a role.
These new data provide confidence on the current geomechanical model helping to optimize the upcoming stimulation operations in the area.
Lessons Learned: Refracs from 1980 to Present
Authors: Grieser Bill , Calvin James , Dulin James 
Published: January 2016

Abstract
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
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.
Eight-Plus Years of Hydraulic Fracturing in the Williston Basin: What Have We Learned?
Authors: Srinivasan Karthik , Krishnamurthy Jayanth , Williams Ryan , Dharwadkar Pavan , Izykowski Tyler , Moore William Ray 
Published: January 2016

Abstract
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.
Production Benefits from Complexity – Effects of Rock Fabric, Managed Drawdown, and Propped Fracture Conductivity
Authors: Britt Larry K. , Smith Michael B. , Klein Henry H. , Deng J. Y. 
Published: January 2016

Abstract
Many shale plays are being successfully developed throughout North America. Numerous studies have attempted to focus on the possible success mechanisms for these unconventional formations. The focus of these studies tends to fall into two distinct camps, (1) complexity and (2) the rock. It is the intent of this paper to show, however, that these two mechanisms are not distinct and independent and that they are in fact very interrelated.
This paper looks at two main issues: laboratory investigation of the stress sensitivity of un-propped fractures for several active unconventional formations, and Discrete Natural Fracture (DFN) simulation of the effect of this on post-frac production.