bluuebunny/crossref_metadata_2025_split huggingface dataset:
PMM-PCP Field Trials Using a New Generation Permanent Magnet Motor Technology
Authors: Saveth Ken 
Published: September 2014

Abstract
The recent proliferation of horizontal and deviated wells along with the low rates being produced by many of the newly completed shale oil wells has created a need for a very efficient pumping system capable of operation below deviations or even in the horizontal. As with all technologies, new materials of construction, new manufacturing processes and new innovative ideas result in the evolution of many systems used in the past. Often times, the needs of our industry demand and direct these innovations as well. Operating companies look for more efficient deployment methods as well as equipment that can operate in ever more demanding environments. The tried and true technologies that are currently being used are no longer enough to meet these new demands. It is during these times, when major innovations occur to allow for completions and production methods to change significantly.
Such is the case in the downhole Progressing Cavity Pumping (PCP) industry. Initially used in industrial applications in the 1930's and adapted for downhole applications via conventional sucker rods in the 1980's, PCP applications eventually evolved into bottom-drive PCPs via a downhole electric submersible motor; hence the term ESPCP – Electric Submersible Progressing Cavity Pump. ESPCPs combined PCP technology with ESP technology thereby eliminating the need for sucker rods thereby widening the application envelope to deviated and horizontal wells within which conventional rod-driven PCPs have inherent limitations. The utilization of "standard" induction motor technology necessitated the need for a speed reduction from the synchronous speed of the ESP motor, to that of the PCP (typically in the range of 100 – 500 RPM). In this case, it was the use of a downhole gear reducer. This gear reducer accounted for the speed requirement differential between standard ESP and standard PCP operational speeds.
In the continued evolution, the downhole ESPCP gear reducer became a costly component and one of the most likely failure points in the system. The introduction of 10-pole submersible permanent magnet motors (PMMs) eliminated the need for an additional piece of downhole hardware. Between 2007 & 2008, a number of permanent magnet motors had been combined with progressing cavity pumps and successfully implemented (PMM-PCP)1.
More recently however, a new generation PMM has been developed that is better suited to be combined with PCPs. This paper will present the results of successful field trials pulling from a large population of wells but focusing on a few key wells to show the improved MTBF.
Drive String Fatigue in PCP Applications
Authors: Skoczylas Paul 
Published: September 2014

Abstract
Drive string (rod string) fatigue failures may occur occasionally in Progressing Cavity Pump (PCP) applications. In a deviated well, the drive string is subjected to rotating bending while the pump is in operation. For each rotation of the string, each portion of the rod's surface undergoes a load cycle of compression and tension. This load cycle is overlaid on the approximately constant torque and axial load that are usually the primary loads considered in sizing a drive string. While the alternating load from rotating bending typically results in a small stress compared to the other loads, it can eventually lead to a fatigue failure.
This paper presents a model for estimating the life of a drive string before a fatigue failure occurs. This model considers the overall stress state in the drive string, the effects of curvature magnification (which occurs near the larger diameter connections in a coupled drive string), and environmental factors. The model has been developed only for solid rod bodies (whether coupled or continuous), and it is not applicable to hollow rods.
This paper also discusses several aspects of lab testing for determining fatigue life. Simple fatigue tests are typically performed under either pure rotating bending, or cyclic bending (without rotation). These tests may not give results that are representative of the actual fatigue life that may result from operation in a different stress state (i.e. when constant torsional and axial stresses are added to the cyclic bending stress).
This paper is aimed at assisting production engineers in designing drive strings for applications in which fatigue failures may occur.
Leveraging Stranded Gas to Energize Temporary Power Solutions and Support Artificial Lift
Authors: Dickert David 
Published: September 2014

Abstract
Unconventional oil and gas developers are currently enduring economic and environmental pressures to produce oil and gas efficiently, safely, and cost-effectively in the remotely located operations of North America's shale plays. By employing alternative fuels, such as stranded natural gas found at the field, to power generators, operators can cut costs, increase production efficiency, and reduce harmful emissions levels.
However, common misconceptions about the ability to effectively use natural gas to power operations inhibit the adoption of this solution by much the oil and gas industry. This paper will present several common challenges to wider use of natural gas power. We will also provide case study examples to demonstrate how alternatively fueled temporary power generation is a viable option for getting operations up and running quickly and maintaining desired production levels.
Shale Oil Production Challenges in Beam Pumping Being Solved with Premium Sucker Rod Designs
Authors: Alvarez Gustavo , Ruiz Rodrigo , Few Jim 
Published: September 2014

AbstractThe shale oil wells are usually able to start producing high fluid rates with enough energy to free flow naturally. After this stage, a high rate artificial lift systems such as ESP or Gas lift is required. But because of the rapid depletion of the stimulated zone during the first year (between 60 – 80% in Eagle Ford), the most flexible form of artificial lift available is used, the beam pumping.Because the pump depth could reach between 4,000 up to 12,000 ft, the beam pumping system is limited in flow rate. A big surface pumping unit and high strength rod are necessary. Other complex challenges to overcome are the combination of crooked or highly deviated well bore, high GOR, propant or sand flow back and the presence of H2S. Small tubing completions in shale wells, with 2 3/8″ tubing installations, pushes the system to provide high fluid velocity with effective solids transportation in low rates and more inexpensive equipment but with sucker rod diameter restriction to 7/8″ slimhole couplings.Optimizing artificial lift equipment selection, sizing, and design will ensure longevity of the equipment and continued production. A premium sucker rod connection has a design that allows the use of 7/8″ and ¾″ strings tapers with KD material to work in corrosive environments with regular size pumping units and lighter strings with guides when necessary in wells where 1″ and high strength rods should be the conventional alternative.This paper explains the experiences of more than 150 strings installed and the benefits achieved in the Eagle Ford.
Accuracy of Nitrogen Temperature Correction Factors
Authors: Sutton Robert P. 
Published: September 2014

Abstract
Nitrogen gas is used to charge the domes in gas lift valves and some downhole safety valves to provide the closing force to shut the valve. The design pressure and temperature conditions in the well must be calibrated to the shop conditions where the valve is set up and tested. Shop conditions are typically established at 60°F so the nitrogen pressure at operating conditions in the well must be corrected to this temperature; hence, the name "temperature correction factor." Currently, the use of 60°F is an industry standard, although earlier shop-conversions pre-1980's offered calibration temperatures of both 60 and 80°F. The significance of the current shop standard is examined and an explanation is offered confirming the standard.
Early downhole design injection pressure conditions were typically in the range of 500-1,000 psig which formed the basis for the development of early tables and charts used within the industry. As more challenging conditions were encountered, the accuracy of these resources diminished and new methods were developed that form the basis of the procedures that are in part used today. These methods were developed using published nitrogen Z factor data that expanded the calibaration range to 3,000 psig and 300°F. The new methods used 2nd and 3rd order polynomial equations as a basis for the model. The usage of these types of polynomial equations for models does not offer an accurate extrapolation as the boundary conditions are approached or exceeded. Currently, the industry is pursuing equipment with design pressures of 20,000 psig so the use of existing models for extreme conditions is suspect. A detailed analysis of the calculation methodology and accuracy of the published temperature correction factor methods at operating conditions ranging up to 15,000 psig and 400°F is presented. As an alternative, a new equation-of-state (EOS) based method for nitrogen PVT properties is also offered to accurately determine temperature correction factors. This method is easily implemented in existing software programs as the only the coefficients in a commonly-used, natural gas EOS are updated to accurately reflect nitrogen PVT properties to 15,000 psig and 400°F.
Accelerated Learning Through Collaboration in a PCP Application: An Australian Case Study
Authors: Sheldon John , Vecere Chuck , Knafl Matt , Johnson Jon , Setiadi Bagus 
Published: September 2014

AbstractFour major operators with significant coal seam gas (CSG) holdings in Queensland, Australia identified Progressing Cavity Pumps (PCPs) as one of the preferred artificial lift technologies to deliquify coal seams and allow the adsorbed coal seam gas to be produced to surface. Each operator also acknowledged the need to accelerate their understanding of PCP technology in order to effectively overcome the unique challenges of this application. To address this need, since early 2012, these operators have met semi-annually to share reliability data on their PCP installations and the experience gained in their field operations. It was found that, through these semi-annual meetings, learnings were accelerated. Possible solutions to key challenges were identified during the meetings, trialled in the field and evaluated for success. The results were then shared with the other operators. This paper describes the process that was used to highlight challenges and identify potential solutions. It also presents examples of solutions that proved to be effective. This collaborative effort shows that challenges can be overcome in a shortened time period, if experience and operational data is shared among operators in similar applications.
ESP Recirculation System in Artificial Sump
Authors: Bridges Jeffrey , Storts Brent , Reid Leslie 
Published: September 2014

AbstractArtificial Lift Case Study: A Mississippian Lime well was tested on an electrical submersible pump (ESP) after previous installations were unsatisfactory.The three main objectives of the test were: (1) to determine if the run life and production of an ESP system could be increased on a gas-slugging well; (2) to implement a downhole recirculation system inside an artificial sump; and (3) to monitor the economic impact of the installation of the ESP unit to the well.The challenges for the ESP system for this specific test included: (i) low liquid inflow during severe gas slugging; (ii) high gas/liquid ratio (&gt;800 SCF/BBL); (iii) difficult startup conditions; (iv) thermal and mechanical damage to motor lead extensions.Due to these challenges, using traditional gas-separation and gas-handling technology was considered a disadvantage. A downhole recirculation system inside an artificial sump was used as an alternative method to prevent potential gas locking, to circulate fluid to keep the motor cool, and to enhance reservoir drawdown.This paper presents basic principles of the application of ESP systems in a gassy and gas-slugging well, principles of implementing a downhole recirculation system, and uncommon techniques to effectively operate an ESP unit in gas-slugging wells. Historical design challenges system-specific design/operation, and production results of the tested well are also presented.
Systematic Study of Bakken Well Performance over Three Well Completion Design Eras
Authors: Yan Changhui , Luo Guofan , Ehlig-Economides C. A. 
Published: September 2014

Abstract
Oil production from the Bakken formation has been active for 60 years and has applied three well completion design strategies in three different eras: mainly hydraulically fractured vertical wells before 1987, horizontal wells before 1991, and mainly multiple transverse fracture horizontal wells since 2006. Reported production data enables comparisons of well performance during these eras.
This study employs the log-log graph of rate (q) versus material balance time (Q/q) to diagnose transient (slope −¼ or −½) and boundary dominated flow (BDF) (slope −1) behavior. Wells from the 3 eras show mainly 3 types of flow regime sequences seen as straight trends on the log-log graph of rate versus material balance time: −¼ to −1, −½ to −1 and −¼ to −½ to −1. Flow geometries corresponding to various flow regime sequences are related to specific well and formation characteristics. Then we extrapolate the BDF behavior to estimate the EUR for each well when possible.
We observed that both the average well EUR and the average well rate at start of BDF behavior is highest for the multiple transverse fracture horizontal well completion design. This project also investigates the behavior of the GOR versus material balance time (MBT). Three types of GOR behavior were observed: constant, constant followed by sharp increase, or scattered. In all three eras, the EUR was highest in wells with constant GOR behavior followed by sharp increase. The sharp increase likely signals flow below the bubble point pressure. The lower EUR in wells that did not produce below the bubble point pressure shows that solution gas drive behavior enhances the EUR. Lower EUR in wells with scattered GOR behavior may be attributed to unstable well production.
This study shows how to use long term production behavior to gain important insights about well designs and why some wells have higher EUR and rate behavior.
Temporal Evolution of the Geometrical and Transport Properties of a Fracture-Proppant System under Increasing Mechanical Loading
Authors: Chen Cheng , Martysevich Vladimir , O'Connell Pete , Hu Dandan , Matzar Luis 
Published: September 2014

Abstract
A fracture-proppant system is used to mimic the interaction between the rock matrix and proppants during the process of fracture closing attributed to pore pressure reduction during hydrocarbon production. Effects of rock type and bedding plane direction are investigated. High-strength sintered bauxite proppants are placed into simulated hydraulic fractures in sandstone and shale rock. There are two bedding plane directions in shale rock; one is 90°, which is perpendicular to the fracture, while the other is 0°, which is parallel to the fracture. Increasing mechanical loading is imposed to close the fracture. Micron-scale X-ray tomography is used to visualize the internal structure. Cutting-edge imaging processing methods are applied to extract patterns of both the fracture and matrix. A pore-scale lattice Boltzmann (LB) simulator, optimized using graphics processing unit (GPU) parallel computing, is used to simulate the permeability tensor inside the fracture. Significant proppant embedment is observed in the sandstone rock when the effective stress is increased to 4,200 psi. Consequently, fracture porosity is reduced by nearly 70%, and permeability is reduced by two orders of magnitude. Embedded proppants are unable to create microscopic fractures on the matrix surface because of the low bonding strength between grains. In the shale rock with 90° bedding planes, when the effective stress is increased to 3,000 psi, significant microscopic fractures on the matrix surface are created because the lamination structure of the matrix is opened. In the shale rock with 0° bedding planes, noticeable microscopic fractures on the matrix surface are not observed until the effective stress is increased to 6,990 psi. Proppant embedment is insignificant because of the high bonding strength between fine grains. Significant anisotropy in the permeability tensor is observed during all experiments. This study is the first to use cutting-edge imaging and modeling methods to quantitatively study the interaction between proppants and the rock matrix during the stress increase process. It has important applications, which help sustain production with adequate fracture conductivity in deep reservoirs (e.g., the Haynesville shale).
A New Methodology to Forecast Solution Gas Production in Tight Oil Reservoirs
Authors: Yu Shaoyong 
Published: September 2014

Abstract
Due to favorable economics, more and more oil companies are now drilling multi-stage fractured horizontal wells to develop tight oil reservoirs. While oil production forecasting in these wells has historically been the primary focus of most operators, gas (solution gas) production forecasting has been largely neglected. There are two distinct reasons for this oversight: First, when compared to oil production, solution gas rates typically have a much lower impact on overall economics. Second, solution gas production is often very difficult to forecast due to abnormal GOR's which are typically caused by incorrect gas rate measurements.
This paper presents a simple methodology to predict solution gas production based on forecasted oil production. This methodology introduces a new specialized plot which can be used to determine various parameters necessary to forecast solution gas production without any costly PVT and pressure history data. Additionally, this paper presents a step-by-step procedure used to analyze the available history to obtain an accurate representation of GOR performance. This data in turn can be used to predict solution gas production.
Missing data and/or incorrect gas measurements are common issues that can directly affect a well's GOR history. The methodology presented in this paper will outline the steps required to repair this kind of bad data and ultimately generate a reasonable GOR forecast that is representative of a well's true performance.
This methodology was initially validated using synthetic data (generated by a commercial simulator) and has been subsequently tested on over one thousand oil wells that are producing from tight formations such as the Bakken, Niobrara and Wolfcamp in the USA and the Cardium in Canada. Each test was carried out by hindcasting – using the early part of production data to history-match the later part of history. This methodology has consistently resulted in good agreement between the forecast and the real field data.
A number of practical examples from different reservoirs have been presented in this paper to illustrate/validate this new methodology.
Horizontal Well Injection Profiling Using Distributed Temperature Sensing
Authors: Foo David , Krislock Jeremy , Meador Trevor , Cheng Teresa 
Published: September 2014

Abstract
As industry moves towards waterflooding horizontal wells, monitoring and maintaining the injection profiles has emerged as a reservoir management issue. Heterogeneities in the reservoir, completion design, and completion problems can all contribute to non-uniform injection and a corresponding drop in waterflood efficiency. Knowing where the water is being injected along the length of a horizontal water injection well is critical to maximizing secondary recovery. Operators need to monitor for channeling of water injection between horizontal injectors and horizontal producers and gather information capable of determining the best way to remediate problems. Operators have begun using distributed temperature sensing (DTS) to measure the temperature along a horizontal well and infer the injection profile from that data. Based on this information, a workover can be done to redistribute the injection, resulting in lower watercuts at the producers and improving the secondary recovery factor.
This paper covers the techniques used to determine the injection profile with DTS, focusing on a case history from the Cardium formation in the Pembina area of Alberta. The well and reservoir conditions are summarized, the completion is reviewed (with microseismic data showing fracture geometry on the injection well), the injection profiling methods are covered, and the results are shown. The operator's remedial efforts are then covered, along with preliminary results.
Reservoir and Drilling Engineering Combined Effort to Develop a Naturally Fractured Over Pressured Shale Formation: Understanding and Operational Specific Procedures
Authors: Badessich Matias Fernandez , Krasuk Raul 
Published: September 2014

Abstract
In the area of this study, the Quintuco-Vaca Muerta complex is an ultra-low permeability, highly over pressured, laminated calcareous and shaly rock that extends over 5000 km2 with an average gross thickness of 700 m. It overlies some 30 meters of what is known as the kitchen of Vaca Muerta, a world-class, high TOC source rock, the main source rock for the Neuquen basin in Argentina. Whenever found naturally fractured, it can produce high quality oil at attractive initial choked rates as high as 1500 bopd.
Historically, throughout many drilling campaigns, it has been very difficult to anticipate where it will have enough good reservoir properties such as to grant a commercial completion. Many times in the past decades, as soon as the wells showed important kicks during the drilling phase in Quintuco-Vaca Muerta, the wells were completed without any further evidences other than high initial productivity indexes. This led more often than not, to wrong decisions and the completions turned out to be sub-economical.
Drilling operations through this geological sequence present severe well control related problems such as difficulties anticipating pore pressures, predicting fluid influx levels and mainly the fact that an increase in mud weight in most of the wells, instead of leading to well control, exacerbates formation fluid kicks and influx pressure.
Combining geological knowledge, production history, downhole pressure while drilling (PWD), surface underbalanced drilling (UBD), mud logging data and drilling experience, a specific underbalanced drilling methodology was developed assuming one main hypothesis which is that in some areas of the field, the formation is naturally fractured and it is potentially critically stressed. This drilling methodology defines how the optimum mud weight is identified, how to deal with formation fluid influx and the well killing procedure; additionally a "dynamic soft well shut-in method" was defined.
An integrated effort of drilling and reservoir engineering allowed the operator to design and execute a meaningful short reservoir limit test that facilitated the evaluation in real time of the size of the accumulation and the reaching of an informed decision on whether or not to complete the well from this interval.