This work represents the first part of a three -stage research program that consists of: a) lab scale test; b) field scale test in an experimental well and c) adjustment of existing mathematical models based on experimental test and actual oil wells.The objective of this first stage was not to develop mathematical correlations that can be applied in the field, but to gather well controlled data that can be used to look for trends and test simple theoretical models.The experimental results of liquid fall-back measurements in intermittent gas lift are presented. The variation of liquid fall-back with changing injection pressures, amount of gas injected and initial liquid column above the plunger are described. The plunger velocity is measured by means of proximity sensors able to detect the metallic plunger. The amount of liquid produced is determined in two ways: a) by using a weighting tank separator at the tubing outlet and b) by using pressure transducers in the bottom of the production tubing which measure liquid column height, before and after the gas injection.The experimental work was carried out using 2 3/8" tubing of 63 ft in length. The liquid being lifted was water and compressed air was used to lift the water.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCurrently in Lake Maracaibo there are nearly 2000 wells on Intermittent Gas Lift (IGL) with an average production of 150 BPD, so a method to estimate the IPR curves in such wells is necessary and important. Considering that in IGL the bottom hole flowing pressure is an instantaneous value continuously changing, then the correct and precise way to determine the IPR curve is through a production test along with a downhole pressure survey. However, many times this method is not economically convenient in highly depleted wells, as it does in a typical intermittent gas lift well. Since there is no publication reported on this subject, the purpose of this work is to get the equations that relate Vogel's model with field data for IGL wells and a numerical method to solve these equations in order to obtain an IPR estimation. Through these equations more realistic values can be obtained, and therefore a better match can be reached between simulators' outputs and field data. These equations will help the field engineer to properly analyze and design these types of wells.

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Engineers have used standard techniques for decades when analyzing sucker rod wells, such as: API 11L standard, wave equation numerical simulation, acoustic logs and dynamometer card acquisition and processing. Each technique has a particular goal and they complement each other. API 11 was developed in the fifties as an easy and hand computation procedure for estimating the production and operational parameters (loads, stresses, torque, etc). Later in the eighties the desktop computers came into the market making the wave equation approach reasonable and popular. The acoustic logs and dynamometer card have been diagnosis tools in the field, which have been boosted by the portable computers. However, none of these tools is able to generate the pump performance curve equivalent to those provided by the electrical submergible pump (ESP) or progressive cavity pump (PCP) manufacturers. Piston pump manufacturers cannot generate that curve at the factory because they only can measure the pump's slippage (leaks in valves and piston walls) but the pump performance also depends on the following parameters: rod and tubing stretching, the rod fundamental frequency, which change in each completion. In the present paper the approach and algorithm to generate the Piston-Tubing-Rod Performance Curve (PTRPC) is shown, which gives a new complementary tool for engineers. Some examples show usefulness of this innovative concept in Sucker Rod Pumping. Finally, the way to introduce the PTRPC in a Nodal Analysis is presented. Introduction Sucker Rod pumping (SRP) is one of the most widely applied artificial lift methods around the world because the operational conditions of the majority of the wells fits within the application window of this method [1]. SRP can handle easily rates up to 1200 BPD, used at depths up to 8000 ft, outstanding resistance for thermal process (600°F), suitable for gas handling, excellent performance with extremely viscous fluids, and very good overall mechanical efficiency (60%). In addition, SRP is a robust and reliable method, easy and economical to operate; besides field engineers feels comfortable operating SRP not only for the acquired experience but also for the huge amount of literature knowledge in this area. Contrary to the appearance, SRP is a very difficult method to be simulated proper and accurately, because there are many phenomena involved: The piston compression process, the rod dynamic and stress analysis, the surface unit geometry and kinematic. At the begging of the 20th century the engineering computations for equipment sizing were based on static analysis. Later in 1939 Mills[2] introduced the acceleration factor into the static analysis to correct the minimum and maximum polished rod loads as well as the effective plunger stroke. Even though Mills' contribution was a considerable advance, as wells became deeper it was not good enough for a proper sizing and understanding of the dynamometer card. In 1954, a group of users and manufacturers of SRP undertook a study based on analogical simulation obtaining as result a set of graphs, tables and charts representative of the dynamic of the piston-rod-surface unit system. These results together with a defined procedure were so useful and practical way to analyze and calculate SRP equipment that was published as the API 11L [3] standard by the American Petroleum Institute. These sets of graphs are the numerical solution of the differential equations that govern the system taking into account many completion details (unit geometry, piston and rod diameters, etc.). With this graphical solutions the field engineers in the fifties and sixties had a hand computation procedure that replaced a simulation running at mainframes, huge and expensive computers affordable for big corporations and available for computer skilled professionals only. The API 11L has been widely used but people are unaware of its assumptions and approximations, such as: low fluid viscosity, vertical wells, one phase fluid, the rod's dynamic is similar to ten strings coupled in serial.

Summary Ultrasound or a high-frequency (20 kHz to 100 kHz) pressure wave has been used in diagnosis and treatments in different areas, such as: medicine, dentistry, civil engineering, and many other industrial applications. In the oil industry, there are applications (i.e., pipeline inspections, fluid velocity measurements, etc.), but to the present, these applications in formation stimulation have been incipient, and only a few lab and field test experiences have been reported. Stimulation with ultrasound is not a common operation offered by oil service companies. To visualize the real potential of ultrasound in oil well stimulation, it is necessary to understand the wave phenomenon, its properties, the parameters that define its behavior, and its interaction with the propagation media. This basic knowledge and the understanding of the different formation damage mechanisms are the keys to comprehend the real potential and application window of the ultrasound in oil well stimulation. This paper presents the theoretical basis of ultrasound and wave phenomena that must be considered when considering stimulation with ultrasound. Finally, some suggestions about the application window of this technology are given. Introduction Ultrasound has been applied in many areas, such as diagnosis, quality control, inspections, cleaning, etc. Industrial cleaning is achieved by flaking out the particles with a mechanical action of the pressure waves (Fig. 1). Usually, the piece is submerged in fluids inside a container with walls that have ultrasonic sources. Clearly, there is a great difference with an application for oil well stimulation, in which the source is running inside the hole, and the cleaning area is around the source. Each application has a particular frequency and power associated according to the sample dimensions and the purpose. For example, the power and frequency used for control echography in pregnant mothers are different than ones used in muscular therapeutic treatments. In the first case, it is enough to detect an echo with high resolution (higher frequencies). In the second case, energy is required to be transferred to the tissue, but high resolution is not required (lower frequencies). It is clear that the purpose and the propagation media affect the ultrasound parameters, highlighting the importance to understand which are the damage mechanisms in which ultrasound can be applied and vice versa. The advantage of applying ultrasound comparing with conventional stimulation is that no invasion or external fluids are required. Ttherefore, fluid/rock interaction analysis is avoided, and the placement as well as the associated equipment and risky operation of handling high pressures at the wellhead is also avoided. Additionally, ultrasound allows underbalance treatments without shutting in the well. Ultrasound cleaning is not a common tool offered by service companies in the field. Only field tests in China and Russia have been reported with more qualitative than quantitative information making these tests inconclusive. Recent references about lab experiences and tool prototypes suggest the potential of this technology. However, ultrasonic stimulation has little understanding of the phenomena taking place in the porous media, and how the waves are interacting with the matrix and the trapped particles. The parameters for suitable cleaning with ultrasonic treatment are not well defined, and how these parameters change while the wave is propagating in the porous media is also not clear. Power requirements for stimulation and effective penetration depend on the elastic media (matrix), the radial geometry, and completion (i.e., either open, gravel packed, or case hole). Wave phenomena as reflection, transmission-refraction, diffraction, and interference must be considered; otherwise, a successful application in Russia can be a failure in other places, because change in one or more parameters considerably affects the wave.

Hydrocarbon allocation becomes essential when facilities are shared for various contributing wells or reservoirs. Uncertainty in the reassignment factor can significantly impact operators’ daily decisions, reservoir health, and ultimately the organization's financial investment. Historically, most oil companies rely on the latest production test done at the actual choke to calculate the produced volume per string, regardless of changes in well performance over time. But this simplistic routine leaves a gap between estimated and actual rates that require more user interventions for manual inputs or corrections. This paper illustrates an example of hydrocarbon allocation process from a smart field. An intelligent optimization system that receives real time data instantly automatically back allocates the field rate based on continuously-tuned well performance curves at wellhead node. This system is capable of managing large amount of data as well as combining analytical models, data mining with predictive analytics, bringing significant benefits to reservoir management, and surveillance process. However, it was found that the field correction factor fluctuated about 25%, when some production optimization and well operations were performed due to inconsistencies in well performance curves. The traditional methodology to calibrate well models starts by choosing the nearest multiphase flow vertical correlation to the measured pressure gradient, reducing the error between calculated and measured points by tuning the "L factor." This procedure cannot ensure that the resulting model will satisfy other production tests at different flowing conditions, which reveals the difference between accuracy and consistency. In contrast, the present effort suggests a practical approach for better estimation of daily well rates as well as improving allocation process, since it attempts to minimize the error between representative production tests and well performance curve rather than reproduce a high accurate bottom hole pressure for a particular flowing condition. Additionally, a more representative productivity index is derived from this change. This novel approach showed better well rate estimation for different flowing conditions reducing reassignment factor deviation below 5%. Consequently, it proved that having a more consistent well model tuned by representative production tests and controlled by real time data, enhances oil back allocation process.

Electric Submersible Pumping is one of the predominant lift methods used in Barua-Motatán field of Tomoporo district, Venezuela. Each year the increasing number of ESP failures has become in a crucial issue for the Venezuelan oil company (Petróleos de Venezuela - PDVSA) due to the adversely effecting on lifting costs, rig utility and production. A dual ESP (dESP) completion in which the second pump is used as a backup is proposed in this study as an alternative for optimizing production, increasing ESP run life, reducing unscheduled deferments and minimizing ESP related well services and associated costs. A critical techno - economics analysis of different proposal from local ESP vendors showed that the suitable option due to space restrictions (casing 7–5/8 in.) is a pod type completion in which primary and backup ESPs are in serial. A risk assessment confirmed the feasibility of the application of dESP in Tomoporo district. The Net Present Value (NPV) of using the new scheme completion proposed is always greater that the conventional single ESP scheme. The high initial capital expenditure incurred from the use of the technology is offset by the significant increase in the profit margin related to the decrease in operational cost and steady production. The most important and unexpected achievement was that probabilities of having negative NPV are reduced considerably with dESP as could be confirmed by risk analysis. Finally, dESP application simplifies drilling scheduling which enhances the planning of well interventions. Introduction One of the mayor objectives of "PDVSA", the Venezuelan state Oil Company, is to develop and increase the production of Tomoporo district (located in the Trujillo state of Venezuela). In order to achieve this goal, PDVSA has been implementing Elecrical Sumersible Pumps (ESPs) as an alternative to handle high production volumes. With this purpose, Caicedo et al [1], carried out a study in this oil field to evaluate the technical methods. In this study was identified that there are many opportunities of increasing production and reduce the gas compressor dependence. However, even though there is an increase in production, it is a major concern that the number of workovers required to replace failed pumps would reduce production efficiency and increase the operating costs of the field. Furthermore, the impact of these facts would be significantly higher when considering lost revenue from deferred oil production while scheduling a workover. To mitigate the effects of pump failure, a dESP system is considered and recommended for the development. In this case, an independent backup pump is justified due to the frequent ESP failures that have been observed in some wells. It is expected that the dual system would allow the longest period of uninterrupted production from the reservoir. Clearly a dESP completion is more complex and expensive than a single completion, and the costs are slightly greater than two single ESP. So a detailed study must be done to justify this investment. The study should include the completion design for each pump based on nodal analysis, the details events to be solved and economical analysis using Monte Carlo approach. This study will be focusing on a feasibility study of the first application of dual "Backup" ESP in one well of the Tomoporo field, based on a technical as well as an economical analysis in order to evaluate the feasibility of installing dESP system in Tomoporo field.

Recent experimental studies on intermittent gas lift have shown that the lift efficiency of this method decreases drastically as the viscosity of the fluid to be lifted increases. As the viscosity increases more gas is needed to keep the fallback losses at a minimum. One way to get around this problem and eliminate fallback losses is to implement the use of Gas Chamber Pumps (GCP's). GCP's are highly appropriate for shallow wells producing heavy oil in places where high-pressure injection gas is available. That is the case of some wells in Lake Maracaibo and in some places in the eastern oil fields in Venezuela that are currently producing oil of 14 to 23°API from reservoirs located at depths between 2000 and 3500 ft. A variety of different GCP configurations can be found in the literature, from highly complex and compact units to simple types of completion that can be implemented with minor changes of current gas lift completions. The advent of simple and highly reliable programmable surface controllers is making it possible to simplify subsurface completion. The simplicity of these new completions implies a new and economical way of implementing GCP's where they are appropriate. A description of how different GCP's work and the most popular configurations are given in this paper. It is also explained in detail a new and simple engineering procedure to estimate the liquid production and gas consumption of a well producing with a GCP. This procedure takes into account the inflow capability of the well and couples this capability with the pressure losses across the different parts of the completion and the flow and pressure capacity of the gas lift system. Introduction Even though in many operational situations GCP's are more efficient than sucker rod pumps, currently they are not widely in use. One reason for this to happen might be the lack of injection gas in areas where sucker rod pumps are being used. The early methods, such as the one depicted in Fig. 1, consisted in alternately injecting gas into a down hole accumulation chamber and bleeding it off to allow it to refill. In Fig. 1, surface valve # 1 is open and surface valve # 2 is closed while gas is being injected. For this type of completion, during the gas injection stage the liquids are forced into the well annulus through a down hole valve installed in a standard side pocket mandrel. This valve is equipped with an internal check valve that does not allow the liquids to return to the tubing chamber. Once the liquid level has reached a minimum, which is at the down hole valve depth or above it, surface valve # 1 would close and surface valve # 2 would open allowing the injection gas to be vented to the surface flow line. The pressure in the tubing chamber then drops to a pressure close to the separator pressure so that the liquids can flow from the formation to fill the tubing chamber again. There are many different types of gas chamber pumps that are explained below. The advantages of using GCP's over other types of artificial lift methods are as follows:They are able to manage sand production with fewer problems.They can lift gassy or viscous fluids better and high fluid temperatures will not affect the subsurface completion.Some types of completions can be very simple. More complicated pumps can be wireline retrievable which is ideal for offshore installations.Their use reduces the changes of creating emulsions.Compared to gas lift, GCP's can significantly increase the drawdown on the formation. They can also be combined with gas lift to get maximum formation drawdown at maximum production rate.GCP's can provide full pump stroke at any depth or cycle rate.They can be installed in deviated wells and can be run and pulled with wireline equipment.