bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analyzing and Troubleshooting Plunger-Lifted Wells
Authors: Rowlan O. L. , McCoy J. N. , Podio A. L. 
Published: December 2007

Abstract
Development of a new portable monitoring system has taken the guesswork out of plunger lift analysis, troubleshooting and optimization. During one or more plunger lift cycles at high sampling speeds this system acquires data from the tubing acoustic signals plus pressure recordings from both the tubing and casing. The plunger generates an acoustic pulse as it falls through each tubing collar recess when the well is shut-in. Each acoustic pulse travels through the gas in the tubing and is detected at the surface. The pulses are converted to an electrical signal by a microphone and pressure transducer. The signals are digitized, stored and processed in a computer to determine plunger position, plunger fall velocity, and plunger arrival at the liquid level in the tubing. By analyzing the collected data the operator can ensure that the plunger reaches the bottom of the tubing before the end of the shut-in time period. Setting the well's controller to have the shortest possible shut-in time period can maximize oil and gas production from the plunger lift installation. Example data collected from various plunger lifted wells are presented in this paper to show how to identify operational problems such as holes in the tubing, stuck plungers and plungers not getting to bottom.
The problem of not knowing the plunger location during the operation cycle has been overcome with this new technology by allowing the operator to see the plunger location at any time during the cycle. Having a detailed analysis of the operation of the well makes optimization of plunger lift production achievable with a minimum of effort and avoids the usual waste of time due to trial and error procedures. Knowing the plunger's location is equally important for timer-based as well as intelligent controllers, since in both cases it is necessary to make initial estimates of the appropriate shut-in time, plunger arrival time and plunger fall time. The capability to calculate the volumes of liquid and gas produced during the cycle and determining the well's inflow performance gives valuable information to determine the opportunity for increased production. Determining the position and velocity of the plunger throughout the cycle can aid in maximizing oil and gas production of a plunger lift installation.
Chemical Automation: A Part of the Well-Centric Production Optimization Loop
Authors: Lee Jaedong , Vachon Guy , Vega Patricia , Means Mitch 
Published: December 2007

Abstract
One of the main challenges in the oil industry is to optimize production while reducing the development costs and maximizing reserves. Real-time optimization has been gaining ground to effectively face these challenges, and has been applied in the smart or digital fields. Literature references two optimization loops, the reservoir-centric slow loop and the well-centric fast loop. Intelligent wellbores are focused on the fast loop and combine well-centric technologies with monitoring, data analysis, modeling, interpretation and automation to accelerate production, maximize recovery and reduce operating and capital expenditure costs.
As production progresses, the reservoir experiences changes in conditions, including decreasing pressure, changes in GOR and rising water cut, that will increase the possibility of corrosion, and organic and inorganic depositions in the production system. These flow assurance and equipment integrity related issues can affect the overall efficiency of the intelligent wellbores, and they should be included in the production optimization loop.
This paper discusses chemical treatment as part of the intelligent production system. Continuous monitoring and proper chemical treatment of possible sources of problems such as scale, asphaltene deposition, and oil-water emulsions closes the fast optimization loop. Closing the fast loop can be done via interventions to the well or by operation of intelligent well equipment, which allows the well to adapt to the best possible operating condition without an intervention.
Closing the Well-Centric Production Optimization Loop: Dealing with the Reservoir as an Externality
Authors: Vega P. , Vachon G. , Lee J. 
Published: December 2007

Abstract
With the growing demand for hydrocarbons, the need to optimize the well production and the exploitation of the reservoirs becomes critical to increase and sustain the energy supply. Intelligent Production Systems combine well-centric technologies with monitoring, data analysis, modeling, interpretation and automation to accelerate production, maximize recovery and reduce operating and capital expenditure cost. This paper presents the well as the true optimization enabler while still recognizing the interdependency between well and reservoir-centric production optimization. Once the completion is deployed and well is put in production, the reservoir becomes an externality and its optimum exploitation can only takes place through proper manipulation and operation of the well. The well-centric closed loop production optimization process involves the ability to sense the operating environment to detect and diagnose under-performing conditions and dynamically adjust production controls to maximize the well productivity. The paper presents examples of the value created by the implementation of well-centric technology.
Dispersion Corrections Are Not Just for LWD Dipole Sonic Tools
Authors: Market J. , Canady W. 
Published: December 2007

Abstract
Many studies have been published showing dispersion characteristics for borehole sonic data, particularly for dipole wireline and dipole and quadrupole LWD tools. With the exception of LWD dipole tools, however, the dispersion corrections are often ignored. It is commonplace for the wireline flexural velocity to be used as the shear velocity. This substitution may be acceptable practice when dispersion correction is less than 2%. There are many cases, however, when the dispersion correction exceeds this amount and correction is necessary. The dispersion behaviour is dependent on formation properties, hole size and mud properties. There are tools issues as well - particularly the complex interaction between the resonant frequency of the formation and the frequency response of the acoustic source. Acoustic tools based on broadband sources are particularly susceptible to dispersion induced inaccuracies. For that reason, a properly implemented quality analysis program is critical to ensuring accurate shear velocity measurement.
Closing the Well-Centric Production Optimization Loop Using Intelligent Completions
Authors: Vachon G. , Vega P. , Lee J. 
Published: December 2007

Abstract
Smart fields technology seeks to optimize the exploitation of reservoirs. Intelligent well completions is a technology that enables this goal. It, in combination with production monitoring tools, makes production optimization possible. In this paper, we take a well-centric look at optimizing production by closing the loop from observing well behavior to determining if it is being produced optimally to making adjustments, if it is not. In order to justify the additional cost of an intelligent well, service companies must quantify how much better it will perform than a conventional installation. The paper will propose net present value as a tool for quantification and show how this benefit is realized though increased ultimate recovery, accelerated production or cost reduction. The well optimization loop has traditionally been closed by a human. As intelligent wells gain acceptance, we will move to automated systems. The paper documents how such automation will create value.
Real-Time Production—A Virtual Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters
Authors: Theuveny B. , Kosmala A. , Maizeret P. -D. , Sagar R. K. 
Published: December 2007

Abstract
A number of real time enablements of production engineering workflows shows various degrees of success and uptake upon implementation. It is possible to extract from the various types of challenges and difficulties a number of guidelines to ensure that the real-time production workflow implementations, deployments and utilizations have the largest chance of successes. A number of real time project have resulted in surprising initial drop of production figures rather than being immediate successes is part of the explanation of the 30% drop of the implementations within a first couple of years of commissioning.
With a larger number of implementations now available worldwide, green field operations are designed from day one with smart/digital capabilities. There is little discussion of the actual value of such massive data gathering capabilities, and its initial cost sunk into the overall project capital expenditure. The case implementation of smart/digital acquisition system in brown fields is much more challenging. The tight operational budgets associated with such operations require clear business and value case. The difference between opportunistic value and guaranteed value is a key element of the decision process and must be clearly identified. The paper offers a number of recommendations based on examples to establish the difference between the various approaches.
The issue of initial cost of implementation is a clear showstopper to many of these implementations. They must be managed well and it is quite important that the total cost of ownership be well defined and funded initially. New web based services such as the remote monitoring of ESP pumps or multiphase flowmeters allows for low initial investments to demonstrate the true value of real time production workflows.
The ability of experts to "see" and "act" on data put in the correct context is becoming more and more essential as equipment and measurements are becoming more and more sophisticated. Finally there starts to be a consensus on a new and essential job description of a breed of technicians and engineers who are willing and capable to attend to unscheduled notifications of events from remote production equipment in due time. These "surveillance" engineers are the basis of the success of the deployments of real time production and interpretation workflows.
Modeling Multiphase Flow in Naturally Fractured Vuggy Petroleum Reservoirs
Authors: Kang Z. , Wu Y. S. , Li J. , Wu Y. , Zhang J. , Wang G. 
Published: December 2007

Abstract
A multicontinuum conceptual model is presented and implemented into a three-dimensional, three-phase reservoir simulator, using a generalized multicontinuum modeling approach. The conceptual model, proposed for investigating multiphase flow and displacement through naturally fractured vuggy carbonate reservoirs, is based on observation and analysis of geological data, as well as on core examples from the carbonate Tahe Oil Field in China. In this conceptual model, naturally fractured vuggy rock is considered to be a triple-continuum medium, consisting of (1) highly permeable and well-connected large-scale fractures; (2) low or impermeable rock matrix; and (3) various-sized vugs or cavities. The base matrix system may contain many small or isolated cavities (of centimeters or millimeters in diameter), and large cavities (or vugs) ranging from centimeters to meters in diameter. Vugs may be (1) directly connected to large fractures, (2) indirectly connected to large fractures through small fractures or microfractures, or (3) isolated from large fractures by rock matrix. Similar to the conventional doubleporosity concept, the fracture continuum is responsible for the occurrence of global flow, whereas vuggy and matrix continua (mainly providing large-storage space of source/sink) are locally connected to each other as well as interacting with globally connected fractures. In the numerical implementation, a control-volume, integral finite-difference method is used for spatial discretization, and the resulting discrete nonlinear equations for the three-phase fluids, coupled with each continuum, are solved fully implicitly by Newton iteration. The numerical scheme, verified by comparing its results against those of available analytical solutions, is used to simulate water-oil flow through the fractured vuggy reservoirs of Tahe.
Formation Testing and Sampling Using an Oval Pad in Al Hamd Field, Egypt
Authors: El Zefzaf T. , El Fattah M. A. , Proett M. A. , Engelman B. , Bassiouny A. 
Published: December 2007

Abstract
Carbonate rocks, thinly bedded sands and naturally fractured reservoirs can exhibit a very challenging logging environment when pressure testing and fluid sampling are required. The challenge is due to, at least, reservoir heterogeneity, the nature of matrix and secondary pore systems, and the difficulty of sealing the probes on testing tools.
An Oval Pad was introduced to help overcome all of these challenges. The Oval Pad covers a vertical section of the well bore, giving it the sealing advantages of a straddle packer but still maintaining the operational flexibility of a probe. In particular, the Oval Pad design ensures an effective seal for the probe during formation testing and fluid sampling in the presence of vuggy and/or fractured carbonate rocks.
In addition to the increased vertical sealing area, the oval shape can reduce the sampling time due to a focusing effect the pad has on near-wellbore flow. A multiphase simulator is used to demonstrate this effect in homogeneous and layered zones. Simulations show that when the complete testing system performance is considered, the Oval Pad reduces pumping times compared to a standard probe.
Field examples from a Miocene Nullipore carbonate reservoir in the Al Hamd field in the Gulf of Suez are used to demonstrate the applications of the Oval Pad. The wireline micro-resistivity imager was also used to help characterize the zone and to facilitate test point identification. This field data is compared to numerical simulations to show the advantages of the Oval Pad design over both standard probes and straddle packer options. Examples included demonstrate the value of integrating both imaging and pressure sampling data into the overall petrophysical understanding of reservoir characteristics.
Modeling Dependence Among Geologic Risks in Sequential Exploration Decisions
Authors: Bickel J. E. , Smith J. E. , Meyer J. L. 
Published: December 2007

Abstract
Prospects in a common basin are likely to share geologic features. For example, if hydrocarbons are found at one location, they may be more likely to be found at other nearby locations. When making drilling decisions, we should be able to exploit this dependence and use drilling results from one location to make more informed decisions about other nearby prospects. Moreover, we should consider these informational synergies when evaluating multi-prospect exploration opportunities. In this paper, we present a practical approach for modeling the dependence among prospects and determining an optimal drilling strategy that takes this dependence into account. We demonstrate this approach using an example involving five prospects. This example illustrates the value of modeling dependence among prospects and the value of learning about individual geologic risk factors when choosing a drilling strategy.
Understanding Hydraulic Fracture Growth in Tight Oil Reservoirs by Integrating Microseismic Mapping and Fracture Modeling
Authors: Liu X. , Zhou Z. Q. , Li X. W. , Li Z. X. , Xu Y. G. , Chen B. C. 
Published: December 2007

Abstract
In this case study, fracture treatments in three tight-oil reservoirs in the giant Ordos basin of northern China were investigated using microseismic mapping and fracture modeling techniques to understand hydraulic fracture growth behavior and post-frac performance. Reservoirs of interests consist of stacked fluvial sand/shale deposits, and the target pay zones occur at depths between 1,820 and 2,186 meters. All wells in these tight reservoirs require fracture stimulation to improve productivity. This paper provides a brief summary of reservoir characteristics, but focuses on microseismic mapping results and fracture modeling analysis. This paper demonstrates that integrated studies can help engineers understand fracture behavior.
Enhancement of Gas Productivity Using Alcoholic Acids: Laboratory and Field Studies
Authors: Al-Anazi H. A. , Al-Otaibi M. , Al-Faifi M. G. , Hilab V. V. 
Published: December 2007

Abstract
The objectives of this study were to: investigate effectiveness of alcoholic acids to stimulate Devonian sandstone gas reservoirs, determine the optimum acid formulation, and recommend the best practices to enhance stimulation treatments in gas wells. In this study, extensive coreflood experiments were conducted on sandstone cores recovered from gas reservoirs to assess the effectiveness of various acid formulations (HCl, HCOOH, HCl/HF, and HCOOH/HF, with and without alcohols) in enhancing gas relative permeability. Several solvents and chemical additives were evaluated to remove or reduce trapped liquids. Experimental results showed commonly used completion fluids caused a severe reduction in gas relative permeability. This study indicated that alcohols can be mixed with stimulation fluid to expedite the cleanup of spent acid and help to attain maximum gas well potential directly after stimulation treatment.
Experimental results showed that alcoholic acids have a slower reaction rate with rocks compared to conventional acids having the same acidity. Alcoholic acids can be injected deeper into the formation and their corrosivity can be reduced in hot deep wells with a proper use of corrosion inhibitor type and concentration. Because of low IFT of alcoholic acids, they can be easily injected into tight formation when there are limitations in injection pressure and resulted in deeper stimulation than with conventional acids. This paper discusses a case study on damage diagnosis for a gas well which was recently completed and showed unexpected low productivity. This study proposed an effective stimulation formulation for gas wells and better practices for stimulation design to reduce flowback time needed to lift spent acid and help to achieve maximum production.
Preemptive Downtime Machinery Monitoring on Drilling Platforms
Authors: Wolter N. , Kaci V. , Pitard G. , Andersen P. 
Published: December 2007

Abstract
When Drilling Platforms experience unplanned down time resulting from rotating machinery failure, it is not only costly and time consuming, but impact safety, efficiency and ROI. This paper describes a new total assets value management strategy, based on predictive machinery failure monitoring, in combination with planned maintenance.
Applying condition monitoring concepts to rig rotating machinery, structure born noise and vibrations are monitored, evaluated and transformed into recognizable wear characteristics, enabling early warning of machinery fatigue, avoiding unscheduled down time and loss of production.
Time based signals and frequency spectra graphs will identify machinery condition and correlate the individual components (gears, shafts, bearings) frequency band. With a condition monitoring index, the individual machinery component "real time" condition is identified in relationship to predetermined performance values.
In the Rig Control Center, machinery frequency intensity is identified and monitored in relationship to trending and threshold values, raising alarms in accordance to the CMI index, identifying the need for time based preventive maintenance, avoiding unscheduled down time, increased maintenance expenditures while exploiting machine reserves, without consequential damages with the application of improved logistic maintenance scheduling.
This newly installed preemptive down time condition monitoring system, on top drives, mud pumps, generators and charging pumps, is expected to realize significant reduction in maintenance budgets, while reducing unscheduled down time substantialy on monitored rotating machinery, equal to current standards in power plants, refineries, mining and steel mills.
Total assets management is a significant potential, with real time machinery condition monitoring, in addition to machinery data acquisition points for temperature, pressure, op limits, emissions etc., incorporating time based rig fleet monitoring in a total data acquisition system of multiple rigs, controlled efficiently by experts in a smart room environment.
This paper concludes that all rotating machinery can be integrated into an assets management concept, including preemptive down time condition monitoring in combination with operating data acquisition and logistics, controlled through intranet at company head offices, enhancing operations management and reporting standards, improving over all HSE and ROI.
Special Cement System and Cementing Techniques Improve Zonal Isolation in South Oman Fields
Authors: Laws M. , Riyami A. , Soek H. , Edwards J. , Elmarsafawi Y. , Abdenour S. , Valstar D. , Misran M. , Hassan A. 
Published: December 2007

Abstract
A cluster of fields in the South of Oman consists of heterogeneous platform carbonates at ~4500m depth embedded in salt. These salt-sealed reservoirs have no aquifer support so ultimate recovery will be maximized by injecting miscible gas. During drilling operations, the drilling fluid density has to be high enough to balance the high-pressure carbonate stringers whose pore pressure can be almost lithostatic.
When circulating to a lighter completion brine however a huge drawdown is applied to the wellbore causing a micro-annulus to form between the liner and cement sheath. It is important to close this gap to avoid the miscible gas flowing behind the casing and hence impairing reservoir management. This gas is expected to break through in the higher permeability zones and gas shutoff remedies will be impossible if the casing to formation annulus is not sealed. The increase in ultimate recovery from miscible gas injection will be significantly reduced if gas shutoff in the higher permeability layers is impossible.
A special cement was trialed which expands over time to close this micro-annulus. Other cementation challenges include the narrow margin between formation pore and fracture pressures, the wide range of formation permeability, the extremely sour nature of the reservoir fluids and the salt-saturated heavy mud. Multiple cement logging runs were made to evaluate this cement at various times and with various fluid densities in the borehole. The first three logs were made within twenty-one days of pumping the cement; all before the slow cement expansion occurred. The well bore fluid during the first log was mud with a slightly lower density than that used to displace the cement. The log was repeated with a surface pressure applied, and repeated again with a much lighter completion brine giving a 61000 kPa differential to the liner. The micro annulus expected from this pressure change is over 180 micron. This third log showed all the bond apparent in the second log had disappeared. The fourth cement evaluation during a workover was made twenty-one months later, again in the much lighter brine. This final log showed the cement had expanded and the bond was restored.