bluuebunny/crossref_metadata_2025_split huggingface dataset:
Theoretical Foundation and Design Formulae for Channel and Pillar Type Propped Fractures – A Method to Increase Fracture Conductivity
Authors: Meyer Bruce R. , Bazan Lucas W. , Walls Doug E. , Brinzer Bill C. 
Published: October 2014

Abstract
A mathematical formulation and solution methodology for placing proppant to create open channels and propped pillar packs in hydraulic fractures is presented. The advantage of this methodology is increased fracture conductivity by creating open channels and/or pillars that support the unpropped (or open) fracture region. The technique requires reduced proppant mass and results in enhanced fracture conductivity. The work illustrates that high conductivity proppant is not required.
The paper presents the governing equations, assumptions and a solution methodology for designing open channels and for flow around pillars in propped fractures. The governing equations and assumptions for calculating the surface displacement (in the loaded and unloaded regions) for pressure loading of a strip and circular region in an elastic half-space are formulated in the appendices. Four cases are presented: 1) uniform pressure distribution over an infinite strip, 2) uniform (constant) distribution (i.e., rigid line punch) over an infinite strip, 3) uniform pressure applied to a circular region, and 4) uniform normal displacement over a circular region.
The effects of the closure stress on the proppant and the formation modulus on embedment are discussed and illustrate the advantage of this methodology in formations with high Young's modulus and low confining stress contrasts. Disadvantages and limitations of the procedure are also discussed. A formulation for the equivalent fracture permeability for flow through channel and pillar type propped fractures is also presented and demonstrates the advantage of creating pillars and open channels for enhanced fracture conductivity. Fractures with open channels and pillars have much greater permeability than traditionally propped fractures. However, proppant permeability is not important in pillar and channel type fracture designs. A proppant that is more ductile and one that creates few fines when crushed is more advantageous for channel and pillar type designs.
The design formulae present a simple methodology to allow for easy field implementation based on a volumetric ratio of fluid to proppant stages. The treatment design can be accomplished with standard industry pumping equipment and methods are provided for the fracture design engineer to create treatment schedules that can be employed by current hydraulic pumping technology. The methodology, if implemented correctly, will greatly increase the dimensionless fracture conductivity (by orders of magnitude) resulting in enhanced production while minimizing operational costs associated with proppant quality.
"Slick Water Fracturing and Small Proppant" The future of stimulation or a slippery slope?
Authors: Ely John W. , Fowler Steven A. , Tiner Robert L. , Aro Dustin J. , Sicard George R. , Sigman Tanner A. 
Published: October 2014

Abstract
Over the past 10 years Ely Corp has supervised more than 100,000 "Slick Water Fracture treatments". After more than 30 years of dominance by extremely viscous crosslinked gels, viscous oils, emulsions and foams, the industry has in selection of fracturing fluids, moved to the point that the vast majority of fracturing fluids are either water and friction reducer or combinations of linear gel and or crosslinked gel that is very rapidly degraded to water once in the formation. In a similar time frame our industry has moved rapidly away from specific selection criteria of proppant based on strength under closure and conductivity profiles which were enhanced by both size, particle distribution, and inherent strength. The dominate proppants now used in the industry are smaller proppant such as 40/70 and 70/140 (100 mesh).
The switch to thin fluids was mainly because of intense efforts from individuals such as George Mitchell and other innovative companies who steadfastly believed in the potential of producing from virtually impermeable matrix source rock and were open to try any available technology. The switch to small proppant was driven in most cases by the lack of transport capability of the thin fluids, and in many cases due to lack of available higher strength proppant.
The success of these slick water frac fluids has, in our opinion, been due to creating a drastically different geometry combined with much larger volumes. The type of frac fluids described have been present in the history certainly since the 50's but not with comparable rate and volume and typically not with the dominate proppant being 40/70 or smaller.
The paper will, utilizing our data base and public production data, illustrate what has truly changed the dynamic of fracturing in our industry. We will also illustrate techniques to optimize slick water fracs based on a combination of new generation technology and experience in not only source rock shale but many so called conventional reservoirs which have only now become economical with use of high volume slick water treatments where more conventional viscous fluids failed.
Based on the broad success of these fluids, we will propose a hypothesis for why these fluids and proppants, which defy conventional frac theory, have made the industry more closely evaluate even the most basic frac theories that we have followed for multiple decades.
Optimizing Hydraulic Fracture Performance in the Liquids-Rich Eagle Ford Shale - How Much Proppant Is Enough?
Authors: Al-Tailji Wadhah , Smith Nick , Shelley Robert 
Published: October 2014

Abstract
Multi-stage hydraulic fracturing has been implemented in conjunction with horizontal drilling in order to make unconventional, low-permeability reservoirs economically viable. Earlier studies from the development of the Barnett Shale have suggested that high fluid volumes and low proppant concentrations were necessary to generate sufficient stimulated reservoir volume (SRV). However, other shale plays, including the Eagle Ford, have formation material with higher ductility and exist in an anisotropic stress environment that tend to generate planar fractures, where lower fluid volumes and higher proppant concentrations are more appropriate.
One operator began exploring their Eagle Ford acreage by utilizing sliding sleeve systems in cemented casing, while trying to determine the best depth within the Eagle Ford sequence to target. Once the drilling target was decided upon, the operator transitioned to a plug-and-perf type of completion in cemented casing in order to improve formation contact and recovery. This provided an opportunity to evaluate different completion designs with enough variability in the data to evaluate fracture performance.
This paper will explain the process used to evaluate drilling, completion, and production information in order to discover the parameters that have the highest influence on well productivity. Completion parameters were evaluated against production performance in a variety of ways, including bivariate, multivariate statistical analysis, and neural network modeling. One parameter that was discovered to have high impact was the amount of proppant used per effective cluster, and the data indicated that more proppant was required than what prior experiences in shale stimulations suggested. Changes to the completion and stimulation design were made based on this analysis, resulting in improved production results.
This study was useful in that it helped identify new ways to evaluate completion and production data in the liquids-rich Eagle Ford Shale, particularly in evaluating fracture performance by normalizing by the number of perforation clusters.
Laboratory Investigation of Acoustic Behavior for Flow from Fracture to a Wellbore
Authors: Martinez R. , Chen K. , Santos R. , Hill A. D. , Zhu D. 
Published: October 2014

Abstract
Distributed acoustic sensing (DAS) technology is implemented to monitor downhole audible sounds for fracture diagnosis, leak detection and other applications. While DAS systems have the potential to enhance downhole flow monitoring, its use is currently limited to qualitative interpretation. Future applications of DAS such as distributed flow prediction require quantitative interpretation to determine flow rate, possibly of multiple phases, from acoustic data.
In this paper we use signal processing techniques to determine flow rates from a simulated fractured well. Production into a 5 ½-inch well is simulated by injecting fluid into a fracture. The fracture was originally simulated with a piece of pipe filled with proppant, and then we used a pair of proppant-filled parallel plates with dimensions of 0.2 inch wide, eight inch high, and sixteen inch long, to represent a fracture. Liquid and gas were injected at varying rates into the fracture and into the well. The noise from production was recorded with a hydrophone within the wellbore. Through signal processing, the sound signal collected is transformed into the Fourier domain for insight into the sound spectrum.
Experimental results show that frequency and sound intensity varies with the flow condition. The acoustic signal is sensitive to the flow rate and the type of fluid. The peak frequency indicates the phase of the fluid and its magnitude indicates the flow rate. The frequencies for gas production are in a range distinct from those for liquid production and the sound levels are related to the flow rate for both fluids. Experimental results also show that fracture geometry has an effect on the sound that is generated and sound from production can be used to identify fractures with restricted widths.
Deepwater Gas Zone Shutoffs by Wireline in Openhole Gravel Pack Completions
Authors: Zettner Claudia , Bensmiller Hank , Lane Tom 
Published: October 2014

Abstract
An operating company successfully executed two wireline through tubing gas shutoff (GSO) workovers in high angle openhole gravel pack (OHGP) completions to isolate high gas oil ratio (HGOR) zones, resulting in significantly increased oil production. This paper summarizes the GSO concept, production logging results, completion modeling, job planning, and prejob surface testing of the completion equipment, job execution, and production results.
The GSO workovers were performed on a tension leg platform (TLP) in a deepwater offshore field. Isolation of HGOR zones was achieved by installing a wireline deployed stackable straddle system across the heel of the OHGP interval. Although both wells have OHGP completions for sand control, effective isolation of the gas zone was predicted using completion modeling and was validated by sustained production performance. These wells do not have external casing packers (ECPs) to prevent flow through the gravel pack interval. Isolation of the gas along the annulus is provided only by increased hydraulic resistance in the gravel packed annulus.
The candidate wells had unfavorably HGORs attributed to gas breakthrough from ongoing gas reinjection. To evaluate if production could be improved by reducing gas production, detailed mathematical modeling of an isolation straddle's impact to inflow from the reservoir through the completion was performed. Results suggested that internal isolation could provide effective GSO without ECPs. Optimal straddle length was determined to help minimize production from the HGOR zone without affecting low GOR zones. In preparation for the workovers, multiple surface tests were conducted to test installation and retrieval of the completion equipment as well as integration and function of tools and equipment from multiple service companies. Work on the first well included the first use of coiled tubing (CT) by the operator on a TLP for a workover. After the CT milling of downhole restrictions, 16 components were sequentially installed by means of electric line (e-line) of a stackable straddle system across the high gas zone. After straddle installation, both wells transitioned from being cycled to continuous lower GOR production. The first well produced 5,000 BOPD at 6,000 GOR before the GSO, and was increased to 10,000 BOPD at 1,000 GOR. The second well produced 6,000 BOPD at 6,000 GOR before the GSO, and 10,000 BOPD at 500 GOR afterward.
The keys to success involved strong teamwork and support from multiple service companies using CT milling, completion equipment, wireline, slickline, and conveyance tools. Significant scalability was achieved during planning of the second workover based on observations from the first.
A New Approach for Efficiently Evaluating Highly Permeable Coalbed Methane Reservoirs in Surat Basin, Australia
Authors: Pelling Ross , Thorburn James , Pourabed Hamid Reza , Cheong Boon Cheng , Wun Moh Hsiao , Harfoushian Jack H. 
Published: October 2014

Abstract
Following the first commercial recovery of coal-seam gas (CSG) in the 1990s, the CSG industry in Queensland has grown rapidly due to the abundant reserves (~33 000 PJ) and global demand for LNG. There are currently three LNG export projects under construction on Curtis Island near Gladstone in Queensland, with the first shipment scheduled for middle to late 2014. In preparation for the completion of the first LNG plant, the QCLNG project, operated by QGC, is currently ramping up CSG production in the Surat basin. By the end of 2014, more than 2000 wells will be drilled and connected to the QGC gas-and-water-gathering network, and thousands more are scheduled for drilling and completion in subsequent years of the project. To meet the production target, it is increasingly important for QGC to accurately evaluate the well productivity during the early stage of development to optimise the operation of the field and ensure all LNG contractual agreements are met.
To date, drillstem testing (DST) has been the most common form of evaluating CSG well productivity. However, the improved capabilities of the wireline formation tester (wireline FT) for testing larger coal intervals (between 1 and 15 m) and deriving similar reservoir parameters is making it a popular alternative to the more costly DST. Nevertheless, although facing very few issues in low-permeability coal seams, the wireline FT is unable to create sufficient pressure drawdown in higher permeability coal seams (&gt;100 md) due to the mechanical limit of its downhole pump (&lt;20 B/D). As a result, the wireline FT interval pressure builds up to formation pressure rapidly and stabilises to gauge resolution within the first few minutes. This causes significant uncertainty in the permeability measurement. In view of these wireline FT limitations, operators have been more inclined to evaluate the higher-permeability coal intervals with DST services, therefore motivating wireline service providers to find ways of improving wireline FT capability
This paper describes utilising super flow technique to create sufficient drawdown in highly permeable coals using wireline FT sample chamber module. Superflow simulates closed-chamber DST by using the high volume sample chamber module of the wireline FT tool. Two different superflow techniques have been implemented with positive results. Several superflow tests were compared with conventional drawdown/build-up tests over a number of coal intervals of varying permeability to confirm the validity of the new testing method. The results indicate this technique has extended the wireline FT capabilities to higher permeability coals that have been typically conducted by DST services. The addition of the sample chamber module and corresponding superflow theory, the wireline FT has broadened the range of CSG applications.
Surfactant-Based Fluids Containing Copper-Oxide Nanoparticles for Heavy Oil Viscosity Reduction
Authors: Srinivasan Aditya , Shah Subhash N. 
Published: October 2014

Abstract
Limited research is reported in the area of nano-fluids applicability in heavy oil recovery. Some of the largest reserves in the world are heavy oil reservoirs. Thermal and chemical methods are widely used for heavy oil recovery. This research work investigates the viscosity reduction of heavy oil by adding a surfactant-based fluid containing nanoparticles. The viscosity reducing effect of only the nano-sized copper-oxide particles without surfactant-based fluid on heavy oil is also examined. Copper (II) oxide particles were selected due to their higher thermal conductivity, easy availability, and lower cost compared to metal nanoparticles. Two heavy oil samples (20-21 API°) having different viscosities and acquired from two different wells located in Oklahoma, USA were used for testing. Heavy oil samples mixed with nano-emulsion containing copper-oxide nanoparticles were investigated at different nanoparticle concentration and oil to emulsion volume ratio. Oil to emulsion volume ratio of (1:0.25) was used to determine optimum nanoparticle concentration. The optimum nanoparticle concentration was found to be 0.02% wt., exhibiting the maximum viscosity reduction.The viscosity of oil samples was measured at various temperatures. The performance of this nano-emulsion was also compared to an industrial viscosity reducer. In addition interfacial tension tests were performed with the oil samples. A significant reduction in the interfacial tension of heavy oil was observed after the formation of oil-in-water emulsion. Inherent properties of copper-oxide nanoparticles in tandem with the oil-in-water emulsion might utilize the advantages of both thermal and chemical recovery methods to obtain an enhanced heavy oil viscosity reduction. In conclusion, this nano-emulsion can be an effective oil recovery enhancement option in a heavy oil reservoir.
In-Situ Visualization of Multidimensional Imbibition in Dual Porosity Carbonates
Authors: Alshehri Amar J. , Kovscek Anthony R. 
Published: October 2014

Abstract
Well-performing waterflood usually recovers 50% of oil in place. This number is even lower in fractured carbonates where the injected water selectively channels through fractures towards producers leaving much of the oil trapped in the matrix. To mitigate the low recovery, one option is to reduce fracture uptake by increasing the viscosity of the injected fluids using polymers or foam. Another option, which is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory provided that cores are moderately long and oriented vertically. Besides investigating gravity effects on oil recovery, the effect of surfactant flood mode (secondary flood mode and tertiary flood mode) on the ultimate recovery (UR) was also investigated.
To investigate the predictions of this analysis, core-flood experiments are conducted using carbonate cores and monitored by an X-ray computed tomography (CT) scanner to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems using whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant.
To study gravity effect, the used surfactant reduced interfacial tension (IFT) from 40 mN/m to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Although the IFT reduction was not large (one order of magnitude reduction), recovery factor (RF) increased by more than 4% of original oil in place (OOIP) leading to an incremental recovery factor (IRF) of more than 7%. Another surfactant was used to study the flood mode effect; the used surfactant reduced IFT from 40 mN/m to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary surfactant flood experiment and a secondary surfactant flood experiment. The secondary flood experiment showed an increase of 7% in the ultimate recovery factor (URF) compared to the tertiary flood experiment.
This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the impact of flood mode on UR. Moreover, this work emphasizes on the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily due to wettability alteration but mainly due to gravity effects. Results are presented primarily as 3-dimensional (3D) reconstructions of in-situ oil and water phase saturation.
Standard Operating Procedures (SOPs) as a Catalyst for Culture Change
Authors: Howard Duhon , Jorge Garduño 
Published: October 2014

Abstract
Standard Operating Procedures (SOPs) for oil and gas production facilities are typically written by teams of subject matter experts including at least process engineers and experienced operators. The team is tasked with identifying the most effective ways to operate the facility (based on safety, environmental protection and economic measures). Operating the facility consistently in accordance with the SOPs should yield considerable benefits.
Yet, despite their obvious importance, often relatively little effort goes into SOP development and use.
SOPs are frequently developed late in the project, after the design is completed and construction is well underway. They may be used for little other than operator training. Following the initial facility startup, they may even end up on a shelf collecting dust. In this environment SOPs have little influence on either the design or the operation of the facility.
SOPs however could be so much more. They can be an integral part of the design process and a catalyst for culture change in the industry. Generated early enough they can be a powerful tool for finding and correcting operability issues in the design. Improving the design in this manner should yield a facility that is easier to operate and inherently safer. Effective SOPs that are actually used in the field could have a significant further impact on process safety.
This paper suggests methods for generating SOPs that accomplish the dual goals of improved design and improved, safer operation. The approach involves writing preliminary procedures (high-level and mid-level) much earlier in the design process and maturing the procedures along with the design. Another important feature is that the final procedures are simpler, easier to use, easier to scan and less likely to be misinterpreted.
This paper will also provide background information to understand how we have arrived at this method for procedure writing as well as provide several key examples of learnings from previous projects.