bluuebunny/crossref_metadata_2025_split huggingface dataset:
Testing of Hydraulic Tubing Anchors
Authors: Phillips Walter 
Published: September 2014

Abstract
Hydraulic tubing anchors, similar to the traditional mechanical tubing anchor (TAC), have been around for over 30 years. Unlike the TAC, the hydraulic tubing anchor does not require surface manipulation to set. Differential pressure between the tubing and casing anulus engages the anchor to the casing by way of a hydraulic piston. Technology and materials have greatly improved in recent years resulting in a vast improvement in reliability of this particular tool. To better understand the dynamics of hydraulic anchors, a test rig was constructed to approximate down-hole conditions in terms of depth and holding capacity. The test assembly allows for controlling the perceived depth by way of pressurizing the tubing, or internal bore of the hydraulic anchor. Varying the pressure in the "tubing" simulates the pressures seen at any depth. The holding capacity of the anchor is tested by a hydraulic jack, which is placed under the anchor. The jack, having a known bore, can easily correlate PSI to lifting force placed on the anchor. Numerous tests were conducted at varying depths to find the lifting force required to dislodge, or cause the anchor to slip. Anchor test data as well as analysis of the interface between the anchor and casing are presented.
All Metal PCP Experiences in Orinoco Belt
Authors: Arredondo Manuel , Caballero David , Morety Robert , Delgado Algimar , Ortegano Bernardo 
Published: September 2014

Abstract
In 1997, the commercial development of the large Heavy & Extra Heavy Oil (HO & EHO) resources of the Orinoco Belt (7 to 12° API/Estimated 297 Bbbl of Recoverable Crude Oil) was initiated. Petropiar (a JV between Chevron & PDVSA), was one the first project in the area, and until today it is considered as a reference when it comes to developing the most recently allocated blocks in the area.
After more than 10 years of intensive production programs, some fields are showing signs of depletion and associated production of gas is increasing. In order to improve oil recovery factor, several operators in Orinoco Belt are interested in Thermal Enhanced Oil Recovery (TEOR) projects. In thermal projects, Artificial Lift Systems must be able to operate in cold and hot conditions, reducing workover intervention and associated production losses. PCM, who is involved in supplying Progressing Cavity Pumps technologies to the Orinoco belt since the very beginning, has developed the exclusive & patented PCM VULCAIN™ (All Metal PCP) technology in order to extend the use of PCP technology on these kind of projects; where no elastomer PCP can perform.
In 2011, a project was launched in collaboration with Petropiar optimization department in order to validate PCM Vulcain™ technology in cold and gassy conditions in this field. 2 × 80V1000 PCM VULCAIN™ pumps were installed in selected wells.
Following the demonstration of the PCM Vulcain™ ability to maintain a high hydraulic efficiency under variable conditions of temperature & viscosities (SPE97796) and the subsequent development of the PCM Vulcain™ in TEOR (WHOC11-578), this paper presents how the PCM Vulcain™ technology adapts to the specific Orinoco Belt environment, and what this technology could bring to further development of this heavy oil basin in EOR projects.
Reliability Improvement in Beam Pumps by use of a Unique Methodology Combining Real-Time Automation and Failure Analysis
Authors: Gardner Blair 
Published: September 2014

Abstract
Santos has produced oil from the Cooper Basin, central Australia since 1983. A range of artificial lift systems are used, dependent on fluid rate and reservoir depth with the beam pump the dominant artificial lift system. Historically the fleet experienced high subsurface failure frequency and increasing operating cost. Information regarding pump operating conditions and the root cause of failure was inconsistent in reporting standard and not readily available. As a consequence the details and mode of failure were not well understood. This paper will focus on analysis of beam pump failure root causes and trends, and how the operator has used this data combined with automated equipment to reduce failure frequency and operating cost.
Santos started a program of beam pump automation in 2006. Before 2009, Santos relied on review of individual well files to determine pump operating history and failure mode. No central collation of well history or pump failure information was available. A database was built, which compiled failure details for more than 2,000 pump installations. This database has enabled run life, failure mode and frequency to be tracked and analysed. A program of automation and control upgrades to 85% of the beam pump population has provided greater visibility of operating conditions and parameters by means of telemetry to the office. This information in conjunction with the database is now used to better understand reasons for failure, and to design future downhole configurations as a result.
In 2006, all Santos beam pumps were non-automated and had a failure frequency of 0.4 failures per well per year. Since the implementation of the automated fleet and the database, data shows frequency has reduced by 70% for automated wells. In comparison, the remaining non-automated beam pumps continue to have a failure frequency of 0.3 to 0.4. Since 2006 the beam pump well count has increased by 60% while the number of annual pump repairs has reduced by 30%. The data indicates failure modes are different on wells with automation. As an example, automated wells have a lower frequency of parted rods, resulting from better rod string design and control.
This paper will assist operators to benchmark beam pump run life in similar operating conditions such as the Cooper Basin. It also presents data and findings to support the benefit a beam pump automation and control program may provide. Detailed understandings of failure modes have helped Santos and its joint venture partners gain significant economic benefit, and develop "Best Practice" guidelines for beam pump system design as a consequence.
Viscoelastic Creep of Eagle Ford Shale: Investigating Fluid-Shale Interaction
Authors: Almasoodi Mouin M. , Abousleiman Younane N. , Hoang Son K. 
Published: September 2014

Abstract
Although organic-rich shale formations are being extensively produced in many places in the United States, the unexpected early production decline is still not fully understood. This phenomenon could have many physical or operational reasons. One of the physical attributes is the time-dependent characteristics of the shale mineral assemblage when interacting with the fracturing fluid. Creep deformation is one of those time-dependent characteristics through which rocks exhibit continuous deformation under constant load that affects reservoir completion and hydraulic fracture stimulation. In this study, shale creep deformation was characterized and rheological models were developed. Triaxial creep experiments were conducted on rock samples from the Eagle Ford shale from southern Texas. Samples were tested with water, decane, or without any circulating fluid to assess fluid-shale interaction. Eagle Ford shale mineral compositions were also investigated using X-Ray Diffraction analyses in an attempt to correlate minerals fluid sensitivity. Problems such as loss of fracture width and length due to shale viscoelastic behavior while embedding the proppant can be better understood if the magnitude of shale creep is well characterized. The experimentally calibrated viscoelastic model not only addressed the instantaneous, transient, and long term sample deformations, but also enabled the estimation of proppant embedment depth during production. The creep deformation was most pronounced when the shale was impregnated with water. Decane-impregnated samples produced less creep deformation and the least creep was measured on the dry ones. The theory of linear viscoelasticity was used to model the samples time-dependent deformation when subjected to their respective constant loads.
Dual Application of Polyelectrolyte Complex Nanoparticles as Enzyme Breaker Carriers and Fluid Loss Additives for Fracturing Fluids
Authors: Bose Charles C , Alshatti AIR Bader , Swarts Levi , Gupta Aadish , Barati Reza 
Published: September 2014

Abstract
Guar-based fluids are commonly used as fracturing fluids to form a filter cake, propagate the fracture and carry proppants during a typical hydraulic fracturing job. High viscosity during injection and degradation afterwards are the characteristics of a high quality fracturing fluid that can maintain a highly conductive fracture during production. In order to achieve a conductive fracture, cross-linkers and breakers are added to the fluid. Filter cakes form on the faces of the fracture during injection causing a major pressure drop between the fracture and the reservoir during the production. Degradation of filter cakes formed on fracture faces has been accomplished using chemical breakers Enzymes and oxidizers are the two main classes of breakers. Enzyme breakers have many advantages over chemical oxidizers: they are cheap, are not consumed during their catalytic reaction with guar, react only with the polymer, are environmentally benign, easy to handle and do not damage wellhead equipment.
Different methods of injecting high concentration breakers are still not capable of degrading the residues left after the fracturing jobs. Permeability reduction of proppant pack due to gel residues, width loss caused by the unbroken gel on fracture face and length loss caused by incomplete degradation of filter cake near the tip of the fractures have been previously reported. It has been previously proven that polyethylenimine-dextran sulfate (PEI-DS) nanoparticles can delay the release of enzymes which reduce the viscosity of cross linked guar. This delayed release can be advantageous in order to inject higher concentrations of enzymes by encapsulating the enzyme inside nanoparticles. However, performance of these nanoparticles in reaction with high concentration filter cakes has not been studied yet.
The main objective of this work is to study the feasibility of using polyelectrolyte complex nanoparticles as enzyme breaker carriers and fluid loss additives to be used for hydraulic fracturing applications. Specifically, the fluid loss prevention and clean-up capabilities of the nanoparticle system for fractures propagated in tight formations are studied.
Static fluid loss tests showed a significant reduction, caused by PEC nanoparticles, in both fluid loss coefficients and fluid loss volumes of tight core plugs with permeability values within the 0.01-0.1 mD range.
Fracture conductivity tests, both fluid loss and clean-up, were conducted using HPG gel, HPG gel mixed with enzyme, and HPG gel mixed with enzyme-loaded nanoparticle systems and the results were compared with the baseline conductivity of the system. Significant improvement in the retained conductivity of the proppant pack was observed using the enzyme-loaded nanoparticle system.
Resolving In Situ Stress Regime, Hydraulic Fracture Geometry and Complexity by Comparing Acoustic Well Logging Data Acquired in Horizontal and Vertical Wells in the Montney Formation
Authors: Qiao Yong , Khalid Salman , Faurschou Ken , Knox Kim 
Published: September 2014

Abstract
This paper discusses the determination of in situ stress regime and its resulting impact on hydraulic fracture geometry through an analysis of two datasets that were acquired in a vertical well and a nearby horizontal well in a Canadian reservoir. The hydraulic fracture geometry monitored using microseismic was available for comparison.
When solving the poro-elastic horizontal strain model for closure stress, using analogous Hooke's Law for continuous media, one needs to resolve a stiffness tensor which requires determination of multi-dimensional shear. Measurements done in vertical wells using acoustic data are challenged by the limitation of not being able to directly record a horizontal shear. This limitation is typically overcome by modeling a horizontal shear using Stoneley mode firing. This well-developed technique works better when data is acquired using tools that allow simplified modeling of the tool wave, such as those tools that do not have slots cut in the housing to reduce direct signal coupling through the tool housing and mandrel. With the acquisition of simultaneous horizontal and vertical well data in the study, complementary information from the horizontal well provides a unique opportunity to physically confirm the validity of horizontal shear determined in the Vertical well, thereby providing further confidence in the modeling technique.
The analysis showed approximately 7% acoustic wave anisotropy for both compressional and shear wave in this part of the reservoir. It also indicated both vertical and horizontal transverse isotropic anisotropy presence. This enabled confirming a particular stress regime.
As fracures usually open up against minimum stress, once the three stresses σh, σv and σH are known, a comparison of the three stresses can predict the geometry of the induced fracture. In this case, the comparison of stresses revealed that the induced fractures should have been vertical. However that was not the case in reality. This suggested that additional factors could be impacting the outcome of the fracture. One possible factor is the presence of fine layering and lamination in the rock. When lamination is present induced fracture geometry is governed not only by stress but also by the frequency of lamination.
It was seen that the zone of interest was higly laminated and layered. As such this might have contributed to the observed fracture complexity
Tight Cardium Multi-Stage Fractured Horizontal Oil Well Performance Study Focusing on the Effectiveness of Various Fracture Fluid Systems
Authors: Reynolds Murray , Gallup Michael , Moscoso Krefthelle , Buendia Juliana 
Published: September 2014

Abstract
In recent years, the tight Cardium sandstones of west central Alberta have seen significant new development with the application of multi-stage fractured horizontal wells. This case study reviews the completion costs, economics and production performance of 148 horizontal oil wells completed in the Pembina Field halo areas (west and east), central Pembina, Willesden Green and Garrington Fields.
Production analysis was performed on all wells using the Duong decline curve analysis technique. This technique has been successfully used on tight multi-stage fractured wells in other areas, and has proven successful at predicting long-term well performance and recoveries. Wells were chosen for comparison that were in the same geological and pressure regions, had a minimum of 2 years of production information, and were stimulated with various fracture fluid systems.
In one of the analyzed areas, a definite trend was identified; it was found that wells drilled in a certain orientation performed better than wells drilled with other orientations.
Completions and hydraulic fracturing costs were gathered from public sources in order to understand the cost differences between areas and types of fracture fluid systems. Using decline curves and cost information, full cycle economics were run on the ‘average’ well for each area in order to determine the Net Present Value (NPV) of each area.
This case study shows there is value in optimizing fracture designs through look-back studies, and there is a need to focus on more effective fracture treatment designs in unconventional oil development.
Level Set Method for Tracking the Penetration Front of a Fracturing Fluid in Heterogeneous Reservoirs
Authors: Chen Cheng , Hampton Jesse , Martysevich Vladimir 
Published: September 2014

Abstract
Shale permeability is low enough to require unconventional stimulation treatment, such as hydraulic fracturing. Hydraulic fracturing is now widely used to achieve a larger stimulated reservoir volume by connecting intrakerogen pores, which are otherwise isolated from one another. It is important to monitor and predict the migration of fracturing fluid. The authors studied fracturing fluid injection in a granite rock in the laboratory and observed a sharp penetration front, implying the motion of the penetration front is advection-dominated. Based on this, they developed a numerical model using the level set method to track the penetration front of fracturing fluid. In the model, auto-correlated Gaussian random fields are generated to represent heterogeneous permeability distributions. Reservoir heterogeneity is measured using the coefficient of variation, which is defined as the ratio between standard deviation of permeability and mean permeability. The correlation length in the horizontal direction is much larger than in the vertical direction, implying a horizontal layered structure. The authors investigated the effect of heterogeneity on penetration front motion. Using the same statistical parameters, numerous realizations of the permeability field are generated. A finite difference reservoir simulator equipped with the weighted Jacobi iteration method was then used to solve for the Darcy flow fields, and the level set simulation was repeated to study the collective behavior of the system. In all simulations, the authors observed linear relationships between time and the first- and second-order spatial moments of the penetration fronts. The time derivatives of the first- and second-order spatial moments were the velocity and dispersion coefficient, respectively. With increasing reservoir heterogeneity, velocity decreased linearly, while the dispersion coefficient increased linearly. These observations imply there is a strong coupling between penetration front motion and reservoir heterogeneity. Therefore, to accurately predict the movement of fracturing fluids, it is necessary to effectively characterize heterogeneity of the host formation. This study is the first to systematically investigate the correlation between fracturing fluid penetration and reservoir heterogeneity using the level set method. It has important applications with respect to optimization of fracturing fluid injection.
Geomechanical Characterization of an Unconventional Reservoir with Microseismic Fracture Monitoring Data and Unconventional Fracture Modeling
Authors: Li Qiuguo , Zhmodik Alexey , Boskovic Drazenko 
Published: September 2014

Abstract
Hydraulic fracturing is often the most effective option to stimulate production in unconventional reservoirs to economic levels. Results of stimulation can be mixed unless the hydraulic fracture design correctly interprets the geological and geomechanical setting of the field. In fields with naturally fractured reservoirs, the interpretation is particularly critical because natural fractures strongly influence the final stimulated rock volume. An accurate description of the natural fracture network and the geomechanical properties and stresses of the rock provide the information to optimize stimulation treatment in naturally fractured unconventional reservoirs. However, the uncertainty in some of this information can jeopardize the value of the modeling and the success of the stimulation. One of the key geomechanical parameters, which are often poorly constrained, is the maximum horizontal stress magnitude. Microseismic data are able to map the stimulated rock volume during hydraulic fracturing operations. These data can be used to verify the accuracy of the fracturing treatment modeling.
Here, we present a case study characterizing geomechanical parameters of an unconventional reservoir using a novel technique that includes calibrated mechanical earth models. The technique reduces uncertainty in the geological and geomechanical parameters used to design hydraulic fracture operations, improving the prediction of the final stimulated rock volume.
Downhole Choke Applications and Performance Impact: A Tupper Field Montney Evaluation
Authors: White Aaron J. , Lavery P. E. , Rock L. 
Published: September 2014

Abstract
Murphy Montney has been implementing downhole chokes in a variety of successful applications that have resulted in both significantly improved well performance and facility equipment/chemical cost savings. The specific applications piloted have included:
Rate Restriction Mitigating Sand Plugging Surface Hydrate Elimination Liquid Unloading
The observed reservoir performance improvement and mitigation of downhole sand plugging is the result of minimizing the net pressure condition created within the induced fracture network. Restricted well drawdown minimizes the physical loss of the induced stimulation, loss which leads to the downhole plugging situation. In addition, Montney pressure dependent reservoir responses have demonstrated stimulated reservoir volume (SRV) flow capacity and fracture conductivity improvement/maintenance under higher flowing sandface pressure conditions, significantly enhancing the minimum-contacted-gas-in-place (CGIPmin). A conceptual reservoir model whereby early pressure maintenance and long-term pressure management is required to maximize the EUR and long-term production has been developed.
Downhole chokes are being used in lieu of surface line heaters and methanol injection in the mitigation of surface hydrate formation. By moving the point of pressure and temperature reduction downhole, the Joule-Thompson cooling response across the choke is geothermally regulated.
Success has also been observed in liquid unloading applications. Downhole choking can create a choked flow rate Venturi effect, which by definition is based upon a critical upstream to downstream pressure ratio, a function of the gas specific heat relationship. Choked flow accelerates gas to a sonic velocity across the flow restriction, imparting a sufficient velocity head upon an upstream fluid level to carry a water droplet to surface. The acceleration of fluid droplets across the downhole choke is equivalent to an infinite lowering of the liquid loading rate, limited only by the maintenance of the choked flow condition created across the downhole choke.
The downhole choke permits for a controlled and self-regulated drawdown, creating both improved reservoir performance and well operations. Mitigating surface hydrate formation and frac sand flowback has resulted in significant cost savings. A novel application specific to over-pressured reservoirs is the use of downhole chokes in liquid unloading applications, maintaining high flowing sandface pressure conditions while unloading liquid.
Shale Bedding Impact on Wellbore Stability and Drilling Optimization
Authors: Gao Jordan , Odunlami Tosin , Osayande Nadine 
Published: September 2014

Abstract
It is well known that shale can be a problematic lithology that is capable of creating issues such as tight hole and pipe stuck during a drilling operation. Shale bedding is recognized as one of the key factors that directly contributes to drilling problems. This paper focuses on shale bedding's impact on wellbore stability, which is investigated with the comparison of wellbore stability results of the shale formation with shale bedding and without shale bedding. The geomechanical simulation results show that: (1) the characteristics of wellbore stability polar plot for all well trajectories can be dramatically changed by shale bedding; (2) both well azimuth and well inclination have significant impact on wellbore stability; (3) stress dominated and shale bedding dominated wellbore breakouts can be evaluated; (4) formation strength control and shale bedding strength control wellbore stability are indentified. Based on those simulated wellbore stability characteristics, optimizations for well azimuth, well inclination, well trajectory, and mud weights can be designed for drilling operation to mitigate the potential drilling hazards.