Humphreys, C. R. (Occidental Petroleum Corp.) | Vangolen, B. N. (Occidental Petroleum Corp.) | Allison, A. P. (Occidental Petroleum Corp.) | Yin, D. (Occidental Petroleum Corp.) | Yicon, C. (Occidental Petroleum Corp.)
The performance of artificial lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, this behaviour leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electric submersible pump (ESP), gas slugs can cause cycling of the ESP, which may significantly shorten its run life. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift to achieve the following goals:
Reduce the frequency and magnitude of slugging behaviour seen at the pump,
Reduce the flowing bottomhole pressure without having to land pumps past the kick off point (KOP), and
Improve separation of free gas from the produced fluid before it reached the pump intake.
Two tailpipe systems were tested in a number of wells using both SRPs and one ESP for lift. The systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced inner diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a specialty cyclonic separator with a reduced ID tailpipe, and the packer is located at the lower end of the tailpipe.
Some of these installations are outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet, tailpipe outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial lift system, while also providing data for modelling the flow regime through the tailpipe. The modelling results were used to forecast long-term performance of the system as the well production declines over time.
Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behaviour through the tailpipe, separation effectiveness, and changes in production. Challenges were noted, and potential solutions or courses of investigation are proposed. Conclusions were drawn regarding the overall effectiveness of the concept, as well as the relative effectiveness of the two systems.
We examined the differences between two tailpipe systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid us in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed so as to improve the design, installation, startup, and operation of these systems.
Gas entrainment is frequently encountered in electrical submersible pump (ESP) as an artificial lift method for oil production. When this occurs, ESP suffers from moderate to serve performance degradation depending on inlet gas volumetric fraction (GVF). The resulted pressure surging may cause vibrations and short run-life of ESPs. For better design of ESP system, a mechanistic model is needed to accurately predict its performance with gas-liquid flow. Similar to modeling multiphase pipe flow, the flow pattern identification and classification inside a rotating ESP is thus of great importance. In this paper, we propose a new mechanistic model to map flow patterns in ESP operated under gassy flow conditions. The model is validated by comparing to experimental results with good agreement.
The experimental facility for testing ESP two-phase performance was designed and constructed. The main flow loop comprises a 3" stainless steel liquid flow loop and V" gas flow loop. A radial-type ESP with 14 stages assembled in series is horizontally mounted on a testing bench. Pressure ports were drilled at each stage to measure stage-by-stage pump pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive air is vented and liquid continues circulation. Experimental data are acquired with two types of tests (mapping and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure and surfactant concentrations are controlled in the experiments.
For two-phase flow, ESP pressure increment suffers from more severe degradation as gas flow rate increases. With the performance curves obtained in surging or mapping tests, ESP flow patterns including dispersed bubble flow, bubbly flow, intermittent flow and segregated flow can be identified. The pattern transition boundaries are mapped. Starting from the free body diagram on a stable single bubble, the transition boundaries of dispersed bubble flow to bubbly flow and bubbly flow to intermittent flow are formulated. Based on the combined momentum equation, the transition criterion of intermittent flow to segregated flow is derived. The flow pattern map calculated from the new mechanistic model agrees well with that detected from ESP performance curves.
At a time when oilfield economics call for the most optimized strategies to produce a field or set of wells, reservoir understanding and artificial lift technologies merge as one combined solution to provide top-of-the-class analyses for optimized production and economic success for very challenging projects. One of the most critical aspects related to the economics of the production life cycle is the maximization of net present value (NPV). This becomes even more relevant for wells that have high capital investment and expensive operating costs.
The objective of this paper is to describe the simulation workflow developed to integrate the interactive response of the reservoir as a response to the drawdown induced when artificial lift is placed within a well. Based on the reservoir response, artificial lift operational parameters can be adjusted at each step to maximize the total NPV for a group of wells in a field located in the Middle East. Sample data describes a case of five wells connected to the same facility and completed with progressing cavity pumps (PCPs).
The individual wellbores containing the PCPs were simulated using a steady-state multiphase flow simulator. Single-well models were used to feed the surface network model with flow lines, chokes and a separator. At the reservoir level, a reservoir model for each well was created using a black oil simulator. The use of an integrated asset modeler enabled automated interaction among single models, network model and reservoir models, allowing the creation of an optimization workflow. The integrated asset management software optimized PCP speed for each of the five wellbores to maximize oil recovery, delay water onset and maximize NPV of the field for one year. The optimizer also had to consider several constraints at both the wellbore and surface facility level. Minimum bottomhole pressures needed to be maintained throughout the simulation to prevent the reservoir from depleting prematurely. Water production also had to be limited to match surface handling capacities. Finally, PCPs needed to be constrained based on a maximum operating speed and maximum horsepower consumption.
The workflow created effectively integrated reservoir modeling with artificial lift performance to deliver an optimized operational sequence for the case study, presenting as results PCP speeds and NPV per month. The results of the simulation showed the potential to increase the NPV and oil production by 10.5% and 9.5% respectively. Furthermore, the current workflow is flexible enough to be extended to other forms of artificial lift and has the potential to fully optimize and evaluate complete fields.
Nagoo, A. S. (Nagoo & Associates) | Kulkarni, P. M. (Equinor) | Arnold, C. (Escondido Resources) | Dunham, M. (Bravo Natural Resources) | Sosa, J. (Jones Energy) | Oyewole, P. O. (Proline Energy Resources)
In this seminal work, we reveal for the first time an extensively field-tested, demonstrably accurate and simple analytical equation for the calculation of the critical gas velocity limit (or onset of liquid flow reversal) in horizontal wells as an explicit and direct function of diameter, inclination and fluid properties. For the independently verifiable and first-of-its-kind multi-play field validation study, we carefully assimilate a very large database of actual horizontal gassy oil and gas liquid loading wells from several unconventional U.S. shale plays with different bubble point and dew point fluid systems and varying gas-to-liquid ratios and varying water cuts. The shale plays in our validation database include the Eagle Ford, Woodford, Cleveland Sands, Haynesville, Cotton Valley, Fayetteville, Marcellus and Barnett formations within their associated Western Gulf, South Texas, Arkoma, Western Anadarko, East Texas, Appalachian and Permian basins. Then, after summarizing our comprehensive field testing results, practical production optimization applications of the new analytical equation and advanced use cases of interest are further highlighted in various liquid loading prediction and prevention scenarios.
As opposed to prior critical gas velocity calculation methods (droplet reversal-based, film reversal-based, flow structure stability/energy), video observations both in the lab and the field clearly show continuously-evolving, co-existing and competing flow structures even with simple fluids without mass exchanges. Therefore, this work avoids skewed assumptions on demarcating the prevailing or dominant flow structure. Instead, the new analytical equation developed is based on an analysis of the major forces in the flow field, namely the axial buoyancy vector, the convective inertial and the interfacial tension forces, in combination with an assumption of the onset of liquid flow reversal based on flow field bridging (Taylor instability). Since the new analytical equation was formulated using these minimalist assumptions, this unique characteristic results in the highest predictability obtainable for the critical gas velocity calculation because there is the least amount of uncertainties (fudge factors). The consistent accuracy of the equation against our extensive horizontal well liquids loading database verifies this fact. Moreover, the simplicity of form of the equation makes it easy to use in that every practicing engineer in practice can perform fast hand or spreadsheet calculations. In effect, this equates to having a model as simple as the Turner model but now with additional direct functions of diameter and inclination. Also, the results clearly invalidate the need for artificial variables (such as interfacial friction factor) that cannot be directly measured in any experiment. In terms of usage, the new model is used in liquid loading prevention scenarios such as end-of-tubing (EOT) landing optimization and tubing-casing selection. Evidently, this work proves that no complex, computer-only procedure is necessary for accurate critical gas velocity calculation. This finding has significant speed and improved answer-reliability implications in strong favor of the presented simple equation for use in artificial lift, production optimization and digital oilfield software in industry, in addition to being ideally suited for ‘physics-guided data analytics’ applications in real-time production operations environments.
Latif, Bilal (Occidental Petroleum Corporation) | McKenzie, K. S. (Occidental Petroleum Corporation) | Rodgers, W. M (Occidental Petroleum Corporation) | Stephenson, G. B. (Occidental Petroleum Corporation) | Wildman, S. L. (Occidental Petroleum Corporation)
In unconventional shale plays, the production profile varies dramatically within an extremely short period of time. Wells often produce at extremely high rates when initially completed and deplete rapidly before reaching production plateaus. This rapidly changing production profile presents a significant challenge to engineers designing artificial lift systems. Because of the method's flexibility and tolerance to a variety of producing conditions, gas lift has become a popular artificial lift choice in these wells.
To achieve optimal system performance, engineers often design gas lift installations to produce up the casing early in the well's life. This configuration minimizes pressure losses in the production string, enabling deep injection, improved drawdown, and higher flow rates. As the wells deplete and the production rates decline, the wells must be converted to tubing flow to ensure well stability. As the wells further deplete, they are often converted to intermittent gas lift. Unfortunately, it is not feasible to produce wells with tubing flow gas lift or intermittent gas lift with the typical downhole equipment configuration used in annulus flow wells. Therefore, transitioning to these late-life artificial lift configurations has required a workover rig.
A novel downhole equipment configuration was developed to eliminate the need for a workover rig when transitioning from annulus flow to tubing flow gas lift. Side-pocket mandrels with a special pocket porting configuration were selected to enable annulus flow with enhanced gas passage early in the well's life. To transition from annulus flow to tubing flow, the slickline-retrievable valves were pulled and replaced with reverse-flow gas lift valves. A field trial was conducted to demonstrate and test this completion concept. While more investigation is required to justify full field implementation, the initial results have been promising.
This project demonstrated that it is feasible to produce wells in annulus flow, tubing flow, and even intermittent gas lift with a single completion using readily available, off-the-shelf artificial lift equipment.
Gcali, Cikida (The University of Tulsa The University of Tulsa) | Karami, Hamidreza (The University of Tulsa The University of Tulsa) | Pereyra, Eduardo (The University of Tulsa The University of Tulsa) | Sarica, Cem (The University of Tulsa The University of Tulsa)
Liquid accumulation in deviated gas wells is a major challenge in production systems. Limitations with the use of gas lift, pumping or plunger lift methods add to this challenge. Recently, surfactants have been injected continuously or as batch to help with the well deliquification by foam generation. The batch treatment is done by intermittent application of soap sticks or liquid surfactants.
This study is an effort to characterize surfactant batch treatment as an artificial lift method in horizontal gas wells. Given the practical potential and yet limited number of studies on this topic, the results can provide an experimental source to optimize surfactant application in mature production systems.
The experimental study is performed in a 2-in ID facility consisting of a 64-ft lateral section with 1° downward inclination followed by a 41-ft vertical section. Water and compressed air are the liquid and gas phases, and an anionic surfactant is applied in batches at the heel of the well. First, static tests are conducted to analyze surfactant efficiency in well start-up conditions. The surfactant concentration, initial liquid loading level and gas rate are varied, and the final liquid loading volume is measured as the target parameter. Then, dynamic tests are conducted to mimic the flowing well conditions. Surfactant concentration, liquid and gas flow rates are varied, and pressure fluctuations at the toe are monitored with time. The surfactant batch is delivered after air-water flow stabilization to investigate the surfactant efficiency. In addition, a high speed camera is used to record the flow conditions.
For well startup conditions, surfactant batch treatment is most effective for lower gas flow rates. Furthermore, the efficacy of surfactants is more pronounced at lesser-loaded wells. The effect of increasing surfactant concentration is eminent below the critical micelle concentration (CMC) with no further improvement beyond CMC. Generally, surfactant batch treatment does not significantly improve well cleanup time.
During well production, surfactant batch treatment is most efficient in low liquid and gas flow rate systems. At increased liquid and gas flow rates, with increasing surfactant concentration, its use can be inefficient due to adverse effects caused by foam frictional pressure losses. When the surfactant batch treatment is efficient, its effect increases with increasing concentration until CMC is reached. During severe slugging, surfactant batch treatment eliminates the slug production phase and partially or fully eradicates the severe slugging depending on the severity of the slugs. Generally, no significant trends can be observed between the period of effectiveness and concentration of surfactant.
Goldney, J. Clifton (Pan American Energy LLC) | Mohando, B. (Pan American Energy LLC) | Cometto, G. Perez (Pan American Energy LLC) | Ballarini, M. (Pan American Energy LLC) | Mazzola, R. (Pan American Energy LLC)
The objective of this paper is to introduce the proposed completion designs so other engineers can apply and improve them in their HGOR wells, maximizing gas production and reducing costs.
This paper highlights a pilot project in which chamber gas lift was installed in two unconventional horizontal wells. Chamber gas lift, as a combination of deep gas lift and intermittent gas lift, allows for an efficient, closed completion with cyclic injection of high-pressure gas, which expands and rapidly displaces fluid at high velocity from deep in the well. Development of the system was a collaboration internally and in conjunction with the vendor to install what was historically a vertical well assembly through the curve section and into a horizontal wellbore. The chamber assembly was successfully designed, sourced, manufactured, installed, and operated. To modify the design from vertical to horizontal applications, components were custom-designed to maintain a sealed chamber. Components deemed most likely to fail are replaceable by slickline intervention. Results indicate a sustained lower downhole pressure than the previous intermittent gas lift system, an increase in production, and good chamber-sweep efficiency.
Vizcacheras is a mature oil field with the highest electric energy consumption among YPF fields. This consumption and the limitations in electrical infrastructure have constrained the growth on the number of ESP lifted wells and consequently the increase of production from the field. Permament magnent motor (PMM) technology was indentified as alternative to reduce power consumption in ESP operated wells in Vizcacheras field. This paper summarizes the field trial of PMM in Vizcacheras field.
The methodology of evaluation includes the power losses calculation of each component of ESP system and the use of hydraulic power as means to make a fair comparison between asynchronous motors (ASM) and PMM. The results of the test shows a total power saving about 17% with a significant reduction of current across ESP power cable and lower motor operating temperature.
Gross estimation about the impact of PMM technology on field and country bases are carried out to show the potential value of this technology in order to increase production by making available energy for other projects and making economically viable those wells with marginal production.
The main challenges during the operation of electric submersible pumps (ESP) lifted wells include running the well at its optimal point, while honoring operational constraints posed by the production system, and extending the service life of the equipment. Overcoming these challenges will typically require building and continuously updating a model of the system. Now, due to issues such as high cost of sensors (including installation, calibration and maintenance), difficulty to reach the sensing point or lack of adequate technology, measuring some variables may be very hard or even impossible. An alternative is to develop a virtual sensor (model) to estimate unmeasured variables from measured values of other variables at different locations along the well. This work presents a model developed based on physical principles to accurately estimate key operational parameters of ESP lifted wells. The model comprises three differential equations that express the derivatives of pump flowrate, submergence level and well head pressure. Assuming as known the pump frequency, casing head pressure and production line pressure, these equations are solved numerically to estimate time profiles of submergence level, well head pressure, pump flowrate, pump intake pressure, pump discharge pressure and flowing bottomhole pressure. The model was instantiated and simulated for a particular ESP lifted well, and showed outstanding performance when estimating pump intake pressure and pump flowrate, as compared to a commercial simulator. The proposed virtual sensor exhibits high accuracy using a model with simplified equations, which can be executed quickly and reliably using few computational resources (processing time and memory); therefore, this sensor is completely suitable for direct installation in the ESP well (on a PLC or a RTU) for real-time monitoring, control and optimization. Other advantages of the proposed model include that it (i) reduces the required surface and bottomhole instrumentation, (ii) estimates the values of the variables during the transient between operating points, (iii) can be used to analyze the influence of operating parameters in the well behavior, without affecting production rate, (iv) incorporates a service factor to account for the equipment wear due to normal operation and (v) can be used in the implementation of optimization and control strategies.