bluuebunny/crossref_metadata_2025_split huggingface dataset:
An approach to account ESP head degradation in gassy well for ESP frequency optimization
Authors: Krasnov V. A. , Litvinenko K. V. , Khabibullin R. A. 
Published: September 2014

Abstract
The majority of Western Siberia oil wells in Russia equipped by electric submersible pumps (ESP). Nowadays the common practice is to operate oil well with ESP as close to its production potential as possible. This strategy allows achieving maximum oil rates and economic efficiency according to Vogel's inflow relationship.
Main limiting factor to decrease BHP and increase well's oil production is an ability of ESP to work with high free gas fraction at pump intake. It is well known that ESP fails to generate pressure drop with high gas fraction at pump intake. However, there is no appropriate mathematical model to account it in ESP design properly.
It is often assumed that ESP works well with gas fraction at pump intake below critical and cannot operate with gas fraction at pump intake above critical. Critical gas fraction varies for different ESP types and manufactures from 25% to 35% and even 50% for ESP with gas handling devices like MVP from Centrilift, AGH or Poseidon from Schlumberger. Using this assumption one can conclude that affinity law should work well for ESP with gas fraction below critical. Nevertheless, it is often observed on wells with high gas fraction that increasing of ESP rotating frequency does not affect BHP and production as it predicted by affinity law.
This paper discusses an approach to describe an abnormal well behavior after frequency change. It shows that correlation for ESP head degradation as in SPE 117414 combined with nodal analysis technique allows to predict well behavior with high free gas fraction. It also allows optimizing energy consumption by ESP by varying ESP rotating frequency. Field cases discussed.
PCP Application for Development of Waxy Bhagyam Field In Onshore India
Authors: Karthik N. R. , Jha Mihir , Kumar Amit , Kumar Piyush , Aggarwal Shubham 
Published: September 2014

Abstract
Bhagyam field is an onshore, shallow field containing light sweet oil (27° API) with low Gas Oil Ratio (GOR) (~100 scf/stb). The crude has ~30% wax content with moderate insitu oil viscosity of ~ 50–250 centipoise (cP) with wax appearance temperature (WAT) ~2° C lower than the reservoir temperature of 53° C. With water production, it was initially expected that viscosity of production fluid will rise upto 3000 cP due to emulsification.
Rod driven Progressing Cavity Pump (PCP) system was selected as artificial lift for the field development considering low GOR and relatively high fluid viscosity. To ensure flow assurance of the high WAT crude, various methods such as annular hot water circulation, heater cable, vacuum insulated tubing (VIT) etc were considered. Based on the analogue Mangala field, which is located in the same license area, it was decided to utilize annular hot water circulation as the downhole heating methodology as it provided a significant completion design similarity with previous installation and operational experience. This completion involves running Colied Tubing (CT) clamped to the main production tubing as a secondary string. The main production tubing with PCP stator is stabbed in a production packer for downhole isolation.Hot water is circulated at 85° C down the coil taking returns through the annulus. This arrangement ensures temperature of the fluid inside the main production tubing is maintained higher than the WAT at all times.
In the 1st phase of field development, wells completed with PCP and have been successfully operating for ~ 2 years meeting requirement of flow assurance & PCP run life. However, PCP efficiency was lower in high GOR wells, as downhole gas separation was not possible. For the 2nd phase of development, alternate completion designs which can mitigate the downhole flow assurance challenges and at the same time open up the annulus similar to a conventional PCP application were considered and finally hollow rod driven PCP design was selected as the most suitable method.
The paper details PCP application in Bhagyam field during the first two phases of development, installation & operating practices, lessons learnt & overall system performance.
Optimization Design of Progressive Cavity Pumps via Finite Element Simulations with a Fluid-Solid Interaction Model
Authors: Chen Jie , Wu HengAn , Liu He , Wang FengShan , Shi GuoCheng , Cao Gang , Sun YanAn , Sun ChunLong , He Yan , Ge WeiTao 
Published: September 2014

Abstract
Progressive cavity pumps (PCPs) have been widely used as an artificial lifting device in various oilfield productions due to their numerous advantages. However, some problems still exist during practical applications. In order to improve the performance and promote the application, it is of great significance to optimize the design of PCPs.
In this study, we established a finite element model of PCP, which consists of the stator, the rotor, the lifted fluid and the fluid-solid interaction. The controlling equations of solid deformation and fluid dynamics are solved using different solvers for solid domain and fluid domain respectively, and their results are exchanged through the fluid-solid interface. Partitioned solution algorithm is employed to tackle the problem of this two-way fluid-solid interaction.
For specified design parameters, our computed laden torque and volumetric efficiency of PCP agree well with experimental results of laboratory test, which can verify our model and simulation method. Furthermore, the developed model is used to optimize the design parameters of PCPs, which primarily include interference, stator thickness, elastic modulus and Poisson's ratio of stator. The goal is to choose the appropriate parameters to make the best performance of PCPs. We studied the influence of these parameters on the main performance of PCPs such as laden torque, volumetric efficiency. According to the simulation results, the interference and stator thickness are found to be the two main factors influencing the performance. The influencing rules are summarized, and a comprehensive optimization system of the design parameters is established. Based on these results, we can choose the appropriate parameters and optimize the design of PCPs. Our work can be of great significance for guiding the design and optimization of new PCPs.
Component Analysis With Competing Risks: How Re-Use of Individual Components of an ESP Impacts Reliability
Authors: Bailey William J. , Couet Benoît , Weir Iain S. 
Published: September 2014

AbstractA rigorous statistical study using a semi-parametric survival analysis approach was applied to an analysis of individual components, with competing risks, of an ESP system.Since its proposal in 1972, Cox's Proportional Hazards (CPH) semi-parametric model has become a primary tool for regression analysis of censored data in medical studies and in the aerospace industry. However, Cox's model assumes that observations are time-independent. This is not the case with ESP components as observations involving these, in the same installation, are naturally related and the multiple observations of an individual component through its re-use are also related and time-dependent. In this paper, we utilize some of recent extensions of standard Cox formulation to analyze components of ESP systems where multiple competing risks from individual components exist (intra-component correlations, intra-installation correlations and time-dependent explanatory variables). These model extensions utilize a more involved analysis undertaking and demand some careful preliminary data treatment. The work illustrates the concept of time-dependent competing risks with an example of an individual component, in our case a specific motor, from its first deployment and subsequent re-deployments in different ESP systems in a systematic and unbiased manner.
Optimizing Gas Lift Operations Using Disintegrable Gas Lift Valve Plugs
Authors: Salinas Bobby J. , Xu Zhiyue , Richard Bennett M. 
Published: September 2014

Abstract
Artificial lift encompasses approximately 96% of the US oil well market. Of the wells that use artificial lift, 10% use gas lift for production. As gas is injected into the well, the viscosity of the fluid and pressure is reduced, promoting flow to the surface. In typical gas lift valve systems, dummy valves are installed in side-pocket mandrels to isolate the annulus from the tubing where pressurization is required to test the tubing, test the annulus, set a hydraulic packer, or activate an isolation device. Then intervention would be required to remove the dummy valves and install a live gas lift system. This can be a time-consuming process and can pose risks to existing infrastructure while hindering production time.
This paper presents a newly developed nano-engineered disintegrable composite (DNEC) and its use in gas lift valves. The DNEC gives gas lift valves the flexibility to be installed as dummy valves, but switching to a live valve without intervention. The switch from a dummy valve to a live valve occurs through an in-situ disintegration of the DNEC plug. This eliminates multiple intervention trips and enables immediate production of these wells under optimized gas lift conditions.
The nano-engineered composite plug is lighter than aluminum, but as strong as some mild steel. The DNEC plug has pressure rating of 5,000 psi and will disintegrate in brine during the cleanup process, within 12 to 50 hours, making it an ideal tool for offshore gas lift valve applications. To date, more than 1,000 gas lift valves equipped with DNEC plugs have been successfully installed. The nanostructured composite material, the valve design, the lab test data and a successful case history will be presented.
Hyperbolic Decline Parameters During and After Linear Flow: Field Example from the Barnett Shale Using Public Data
Authors: Pratikno H. , Reese D. E. , Summers L. E. 
Published: September 2014

Abstract
The Barnett Shale is one of the first unconventional shale plays developed with multistaged, fracture-stimulated horizontal wells in the world. It is located in North Central Texas near Fort Worth. At the end of 2013, the Barnett Shale had over 14,000 multistaged hydraulically fractured horizontal wells (MFHW) with approximately 7,600 of these wells with over five years of production history. In addition to these MFHW, there are approximately 4,000 vertical wells.
Production forecasting for unconventional reservoirs with MFHW is a topic with a great amount of interest. The question is what are the appropriate decline parameters to be used in the forecast? Are multisegment forecasts with their own decline parameters necessary?
Currently, production forecasting using a modified hyperbolic Arps equation is still widely accepted. This work provides analysis in characterizing decline parameters during and after linear flow for horizontal wells in the Barnett Shale using public data. There will be examples of MFHWs from the Barnett where the hyperbolic b-exponent will be calculated for each month of production and shown to vary with time as flow regimes change.
Single well simulation will be used to characterize the different flow regimes and their effect on decline parameters. Simulation of wells with and without volume outside of fracture tips and their effect on decline parameters will be shown. The decline parameters were in an Arps forecast to match our single well simulation forecast. Uncertainty analysis of production forecast using simulation models is also presented in this work.
A Methodology to Quantify the Impact of Well Interference and Optimize Well Spacing in the Marcellus Shale
Authors: Yaich E. , Diaz de Souza O. C. , Foster R. A. , Abou-Sayed I. 
Published: September 2014

Abstract
While well interference is a known phenomenon in shale gas plays, it is often overlooked or only considered when its effects are readily apparent. Spacing tests are often performed when starting to appraise or develop a new area where a qualitative evaluation of interference between drilled wells will determine the appropriate well spacing.
While numerical reservoir modelling and build-up analysis can be applied in the Marcellus shale play they are not appropriate for determining optimal spacing due to very low, nano-darcy reservoir permeabilities and uncertainty over hydraulic fracture geometry. The challenge was to develop a new approach to measure and estimate the impact of interference on gas recovery and optimize well spacing.
The impact of interference was initially evaluated by assessing the change in the productivity index of wells due to offset wells being added, put on production or shut/in. In order to have a more meaningful way of estimating its impacts on economics, interference was also quantified based on projected future five year cumulative production using Arps decline curve, Rate Transient Analysis and Pressure Normalized Rate methods. Results were compared and a statistical workflow was used to estimate optimal spacing.
By relating the degree of interference with overlap between wells, the nature of interference was also investigated. Interference can be due to a Stimulated Rock Volume (SRV) overlap. This is characterized by a proportionality increasing interference with SRV overlap. The impact of natural features such as faults or high permeability streaks that can act as conductivity highways across many wells is usually not proportional to overlap.
This study in Marcellus shale play demonstrated that measurable interference occurred at wide spacing and that 1,000 ft spacing should result in an increased FYFCP (Five Year Forecasted Cumulative Production) of 10% over existing spacing assumptions, key at low gas prices. Therefore, 1,000 ft spacing has been recommended for future well placement. The workflow outlined in this paper is currently being used to evaluate well spacing for other assets and can be used by Reservoir Engineers to evaluate spacing in tight or shale gas/oil plays.
Reducing Cost and Risk with Cemented-Back Monobore Well Construction in the Cardium Formation
Authors: Lowe J. , Rey M. M. , Manuel J. J. , Kenyon M. 
Published: September 2014

Abstract
Operators in the Cardium formation of central Alberta are increasingly adopting a cemented-back monobore well design to reduce costs and improve operational efficiency. Extensive field data from more than 360 wells completed by an operator working in this formation demonstrates the operational advantages and substantial cost savings gained by adopting a monobore well design. This paper details the evolution of well construction for open hole horizontals in the Cardium, and provides cost and operational comparisons between drilling different wellbore sizes, running different casing sizes, and using different stage tools to cement from the heel of the well back to surface.
The operator completed 77 wells in the Cardium using 177.8 mm intermediate casing through the build section and a 159 mm open hole lateral with 114.3 mm liner before evolving to a cemented-back monobore design. Analysis of the field data determined that 171 mm vertical and build sections of the wellbore, and a 159 mm open hole lateral with 114.3 mm casing is the optimal cemented-back monobore design, allowing for easier casing installation and providing substantial cost savings by eliminating the intermediate casing.
Monobore ball-drop completion systems require a stage tool to cement from the heel of the well back to surface. By implementing a stage collar that closes mechanically rather than with a wiper plug or dart, the operator was able to reduce wellbore integrity risks and considerably lower drill-out costs before stimulating the well. The operator has completed more than 220 wells using this stage collar with 100% success.
The geology of the upper formations was managed using invert drilling mud to control wellbore stability and downhole pressure, rather than intermediate casing, to successfully adopt a cemented-back monobore well design. The steps detailed in this paper to eliminate intermediate casing from wellbore construction, identify optimal wellbore sizes and reduce drill-out costs have proven to be successful in the field and can be applied to a variety of formations around the world.
Production Forecasting in Unconventional Resources using Data Mining and Time Series Analysis
Authors: Gupta Siddhartha , Fuehrer Franz , Jeyachandra Benin Chelinsky 
Published: September 2014

Abstract
Production forecasting in shale reservoirs is a challenging task because of the complex influences of geology, lithology, stimulation practices, etc. The large well count makes history matching and forward simulation particularly time consuming and laborious. In such a context, it is important to consider alternative methods, and to this end, we have developed two new methods of forecasting production.
The first method uses data mining techniques, which allow the analysis of large quantities of data to discover meaningful pattern and relationships. These can subsequently be used for prediction. Some common data mining tools are neural networks (NN), genetic algorithms (GA), and self-organizing maps (SOM). Our method uses NN for predicting the future performance of a shale gas well based on historical production data of the previous year. The decline in production is captured during the NN training process and applied to the production data during the forecasting phase. The model is simple, elegant and fast and is able to forecast production in an unconventional play with reasonable tolerance.
The second method uses time series analysis. It the trend, changes in value, rate of decline, and correlation with the past to generate a rapid and accurate forecast. The stock markets use this technique, and it is safe to say that if it can predict the stock ticks, then it can yield good results on a fluctuating, but surely declining, production rate.
These methods are elegant and fast and are able to forecast production in an unconventional play with reasonable tolerance. They are not data intensive and can also be automated to be applied to a large number of wells, which makes them particularly useful in integrated operations in which a comparison of actual versus predicted behavior would enable operators to quickly identify problem wells for a more detailed investigation. The methods were applied to wells from the Barnett, Bakken, and Eagle Ford plays.
Production Forecasting in Shales: A Comparative Field Data Study Using Large Well Counts
Authors: Valentine A. P. , Brown A. , Gupta S. , Dwivedi P. 
Published: September 2014

Abstract
As the effort to develop unconventional reservoirs takes on a greater pace within the industry, so too does the effort to understand the way in which these unique reservoirs produce. Classical forecasting techniques such as Arps are typically not able to adapt to the characteristic "tail" exhibited by wells producing from these reservoirs. As such, a tremendous amount of investigation and research has been undertaken to better understand and therefore better predict future performance. As a result the literature is full of alternative techniques.
In this paper we explore a number of these techniques, comparing them to the classical Arps method as a form of benchmark. In addition, we take a "backcasting" approach on several large shale fields, including the Barnett, Eagle Ford, Bakken and Montney. This approach is equivalent to going back in time, hiding later production data, forecasting and comparing forecasts to what we now know production rates to have been. We also test the applicability of classical and newer forecasting techniques on big data sets by identifying changes in operating conditions and calculating decline rates for the period thereafter. As seen in this study, each method has its own "sweet spot" in which it yields accurate results.
This study differs from other published studies in that our focus was not so much on obtaining Estimated Ultimate Recovery (EUR) values that matched the actual production of depleted wells, but rather was on predicting production rates in the relatively near term. While EUR estimation is a key performance indicator, it falls into the domain of the long term planners. Conversely, future production rates are of prime importance to operational personnel and to their short term decision making processes, such as timing of infill drilling and remedial activity, along with surface facility planning activities such as system upgrades or reconfiguration.
Another aspect of this study which differs from others published is that we did not preclude wells with noisy data. Rather, we embraced the challenge presented by real data sets. In this way we could ensure that our proposals could be applied universally and not simply to those wells with well-behaved production histories.
Behind the Numbers: Insights into Large Audit Firm Sampling Policies
Authors: Christensen Brant E. , Elder Randal J. , Glover Steven M. 
Published: September 2014

SYNOPSIS
Changes in the audit industry after the Sarbanes-Oxley Act, including mandatory audits of internal control over financial reporting and PCAOB oversight and inspection of audit work, have potentially changed the nature and extent of audit sampling in the largest accounting firms. However, little academic evidence exists on these firms' current audit sampling policies (Elder, Akresh, Glover, Higgs, and Liljegren 2013). As such, we administer an extensive, open-ended survey to the national office of the Big 4 and two other international accounting firms regarding their firm's audit sampling policies. We find variation among the largest auditing firms' policies in their use of statistical and nonstatistical sampling methods and in inputs used in the sampling applications that could result in different sample sizes. Sampling experts' internal reviews indicate that projecting and resolving identified misstatements is one of the biggest difficulties that audit engagement teams face when using sampling techniques. Finally, we present evidence that some firms have significantly changed their approach to revenue testing due to PCAOB inspections. This evidence provides important insights into current sampling policies and presents opportunities for future research.
Data Availability: Please contact the authors.
The Effects of Using the Internal Audit Function as a Management Training Ground or as a Consulting Services Provider in Enhancing the Recruitment of Internal Auditors
Authors: Burton F. Greg , Starliper Matthew W. , Summers Scott L. , Wood David A. 
Published: September 2014

SYNOPSIS
This paper examines factors that influence job applicants' willingness to apply for positions in internal auditing. We predict and find evidence that job applicants are dissuaded from applying for internal audit positions. In two separate experiments involving participants at seven universities, we discover that this phenomenon is most prevalent for applicants with business experience. Experienced applicants are 20 and 33 percent less willing to apply for a position if it is labeled as “internal audit” versus “accounting” in the two experiments, respectively. In addition, we find that the only experimental condition that increases interest in applying for an internal audit position for experienced applicants occurs when the position advertises the combination of (1) a short stint in internal auditing and then a move from internal audit into a management position, and (2) work primarily related to consulting services rather than assurance services. As a potential explanation for these findings, we find evidence that participants believe other business professionals have negative stereotypes of internal auditing—which likely dissuade potential job applicants from applying to work in internal audit. The results should prove informative to practitioners, internal audit professional organizations, and business professionals concerned with high-quality corporate governance.
Data Availability: Contact the authors.