DESP

This paper was prepared for presentation at the 2013 UPES SPE Fest [10 th -12th February 2013]

The figures, data and text used in the document are at the authors’ discretion ONLY. The UPES SPE Student Chapter does not hold any responsibility for any breach of Copyright and Plagairism laws, in this paper.

AbstractElectric Submersible Pumping is one of the predominant lift methods used in the world. Each year the increasing number of ESP failures has become in a crucial issue to the E&P companies due to the adverse effect 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.

This paper will analyse the performance of a DESP in a range of reservoir scenarios. It will show how DESP performance can be modelled by use of well-performance and reservoir-simulation tools.In Deepwater, subsea, and multizone applications, dual ESP systems can be used in many ways to improve the financial performance of the well. In the series, the two system work together to provide double the lift or doubles the horse power. Parallel systems can virtually eliminate the cost of deferred production caused by workover rig delays or scheduling, acting as an “in-well backup” system.

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.

This work provides a comparison of the drivers for the choice of a single ESP and a DESP in the scenarios studied. It illustrates economic feasibility and various field applications of thus aiding the increased application of this technology.

Introduction

Artificial-lift methods are required when a well ceases to flow naturally or when the production rate is too low to be economical. To create a steady low pressure or reduced pressure in the well bore against the formation to allow the well fluid to come into the

wellbore continuously for getting a steady stream of production to the surface end. ESPs boost the pressure of the produced fluid, allowing an increase in the well drawdown and providing the additional energy required for the reservoir fluids to flow. The typical ESP installation employs a single multistage pump driven by an electric motor (called a SESP in this paper). Currently, it is technically possible to employ more than one pump/motor set in the tubing string (i.e. a DESP).

In general, applications of the second pump have been either to increase the pumping capacity or to act as a backup to improve the reliability of the pumping system. DESPs have been used for managing reservoir issues such as water coning and multiple production zones.

At its most basic, an ESP increases the well drawdown and provides additional energy to lift the well fluid to the surface. In principle, installation of a sensitively controlled DESP across the completion interval is also capable of modifying the drawdown profile in a similar manner. This leads us to examine if they can be used to improve well performance, particularly from a reservoir-performance point of view.

Four different possible applications of DESPs will be analyzed in this paper:

Commingling production from zones with different pressure regimes.

Control of water coning by producing from both oil and water zones in bottom water-drive reservoirs.

Control of water cresting in long horizontal wells by use of DESPs at heel and toe.

Installation of a reduced-power downhole pump at the production zone supplemented by a higher-capacity pump at the seabed for production from deepwater oil reservoirs.

Realistic economic analysis of ESP application has to include the pump’s initial purchase and installation cost, but must also account for the longevity or failure frequency of the ESP. An independent-backup pump would be justified if frequent ESP failure were expected because it would allow the longest period of uninterrupted production from the reservoir.

Multiple Production ZonesMultiple production zones are typically produced from a single well either sequentially or by commingling. The pump-assisted production could be achieved from both zones by use of a downhole SESP and a downhole

Dual ESP: Feasibility & Possible ApplicationsShamit Rathi, Animesh Jain and Shaswat Agarwal, School Of Petroleum Technology, PDPU Gandhinagar

2 Dual ESP: Feasiblity & Possible Applications UPES SPE Fest 2013 – Scaling the “Infinite”

choke. An alternative to this is a DESP completion and commingled production. Dual ESP system design for two production reservoirs in one well gives opportunity to maintain records of produced liquid from each reservoir.It Provides following advantages: Possibility of capital expenditure reduction for

additional oil wells construction; Well operation costs saving; Increase of coverage and multi-zone field

development intensity; Comparative simplicity of design; Differential effect on each layer, with the ability to

control liquids sampling.

Dual ESP can be installed in two ways for production from differernt zones:1. Arrangement of ESP system with it’s installation between reservoirs a packer with cable feed-through system is used.2. If it’s not possible to install lower ESP system between reservoirs, a leak-proof shroud is used with ESP system installed in it.

We a created model to examine this scenario, it consisted of a central vertical well completed in a layered reservoir for the entire height of both production zones (Fig. 2). The general model parameters are given in Table 1 & 2 (see Appendix). Analytical aquifer support representing edgewaterdrive at the lowest reservoir layer was provided for each production zone. The DESP system (Fig. 3) was compared with a completion in which a (common) SESP, Which was installed at the same location as the upper ESP in Fig. 2, was used to produce both zones.

Analysis:An analysis was done by varying different parameters so as to test DESP applicability in various reservoirs:

Figure 2 Dual ESP system Configuration

Aquifer Size. The recovery obtained was highest when the least aquifer support was provided, decreasing as the aquifer becomes stronger because of earlier water breakthrough (Table 5). The DESP completion showed the greatest incremental oil production for the model with the

Figure 3: Schematic of DESP completion for the multiple-production-zone application

Figure 1 EclipseTM network model used,VFP tables were generated by Wellflo.

3 Dual ESP: Feasibility & Possible Applications UPES SPE Fest 2013 – Scaling the “Infinite”

strongest aquifer (Table 5).

Liquid Rate. The oil recovery was accelerated by increasing the liquid rate (Fig. 4). The incremental gain reduced with increasing liquid rate because of increased water coning. The oil recovery over the modeled period (6 years) was higher for DESP system than for an SESP completion. The difference between the two systems varied slightly, but decreased as the liquid rate increased. An average incremental gain of approximately 1% was achieved by the DESP system.

kv /kh Ratio. A kv /kh ratio of 1:3 resulted in maximum recovery and oil production for both SESP and DESP completions. Oil recovery and-production rates diminished for smaller kv / kh ratios. The reduced vertical mobility of oil surprisingly allowed the SESP to achieve a higher recovery and production than the DESP completion when the kv /kh ratio was 1:30

Difference in Zone Pressures. Oil recovery decreased significantly for the SESP completion when the pressure difference be-tween the two production zones was increased. The oil recovery and production rate using the DESP completion remained almost constant, being independent of the difference in production-zone pressures (Figs. 5 and 6, Table 5). This showed that DESP completions become more attractive as the reservoirs’ pressure regimes diverge.

Summary of Multiple-Zone Results. Table 5

summarizes the 6-year production results for the multiple-production-zone scenario. It was found that: small improvement in oil recovery was achieved, inmost cases by a DESP completion compared to an SESP installed above the upper production zone. • An SESP may have significant advantages for very low formation kv / kh ratios, though further confirmation is required of this single simulation result. • DESP completions have a significant advantage compared to SESP completions when the pressure difference between the production zones becomes greater than 200 psi. The DESP’s advantage increased to an extra 6% incremental production for a pressure difference of 600 psi. This makes an attractive DESP-completion scenario.

Water Coning In Vertical Wells

Figure 4 Sensitivity to various liquid rates for the multiple production-zone scenarios.

Figure 5 Recovery factor for various differences in zone pressures with a SESP rates for the dual-zone, ommingled production scenario.

Figure 6 Recovery factor is independent for the tested differences in zone pressures using DESP rates for the dual-zone, commingled production scenario


Another application of a DESP could be prevention of Water breakthrough in reservoirs with strong acquifier support, a prominent well-problem in both vertical and horizontal wells. Various methods are being used in the industry to eliminate this problem [e.g., production below a critical rate, partial completion with perforations distant from the oil/water/contact (OWC), water shut off, and downhole-water-sink (DWS) technology]. DWS along with DESP has been employed by BP in the Wytch Farm field.

In this Application, Water is produced from beneath acquifier separately [as shown in the fig.7], preventing it from mixing in the oil flow stream.This way extra water separation cost is saved and various other problems (eg. Corrosion of internal tubing etc) are eliminated to a high extent, Proving its economic vialbility against extra cost.

Water-Cresting Control in Horizontal Wells DESP completion can also be used to stabilize the water-cresting problem in long horizontal wells and improve production performance (Fig. 8 ). A pump was placed at both the heel and at the middle of the horizontal well in the DESP completion. The VFP tables generated by WellfloTM can used in the EclipseTM model using the network option

Deepwater Oil Production WellsDESP applications in the subsea environment have established the feasibility of coupling a conventional downhole ESP with a subsea booster system in terms of increased equipment reliability and improved economics (Horn et al. 2004).The pumps can be installed in series configuration—one being set at the bottom of a well (low capacity) and another one at a higher level in the well or at the seabed (high capacity). The advantages of such a system are:• The borehole can be of reduced diameter, being based on well productivity alone and not on the minimum pump/motor size for the larger-capacity pump.

• Reduced motor and power-cable capacities for bottom pump because of lower pumping capacity.

• Smaller pumps may be deployable by coiled tubing, thus reducing the lifetime costs.

• Flexibility of manifolding extra slim wells to the pump at the seabed later in the field life.

•

Reduced drilling cost for the smaller wellbore size

Backup Pump

A major concern that the number of workovers required

Figure 7 Schematic of the model for the control-of-water-coning application using a DESP completion.

Figure 8 Schematic of DESP for controlling water cresting in a horizontal well.

Figure 9 Schematic of the application of DESP completion for deep-sea-well scenario.


to replace failed pumps reduces production efficiency and increases the operating costs of the field. Furthermore, the impact of these loses would be significantly higher when considering lost revenue from deferred oil production while scheduling a workover. Thus a “back-up” ESP system is considered and recommended for the development.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.Horizontal Wells

Concluding Remarks

DESP completions have become accepted as a means to improve the reliability and the capacity of the artificial-lift system. Paper identified a number of reservoir scenarios where DESP completion could be preferred to an SESP completion because of improved reservoir performance such as Multizone-production, Water Coning in Vertical & Water Cresting in Horizontal Wells, in deep offshore wells and as a “back-up” system to SESP.

A properly designed DESP completion will frequently show an improved reliability since production could continue from both zones after failure of one of the pumps.

This paper indicates that DESP completions can be viewed as a part of the solution to achieve cost-effective production from certain reservoir architectures.

Acknowledgements

We, would like to express our gratitude to all those who gave us the opportunity to prepare and present this technical paper.We are also deeply indebted to our professors, whose help, stimulating suggestions, knowledge, experience and encouragement helped us in all the times of study and analysis of this subject. And finally our thanks to the UPES SPE Student chapter for the golden opportunity of presenting this paper.

References

Sawaryn S.J. 2003. The Dynamics of Electrical-Submersible-Pump Populations and the Implication for Dual-ESP systems. SPEPF 18 (4): 236-246. SPE-87232-PA. DOI: 10.2118/87232-PA

Vachon, G. and Furui, K. 2005. Production Optimization in ESP Completions With Intelligent Well Technology by Using Downhole Chokes To Optimize ESP Performance. Paper SPE 93621 presented at the SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March. DOI: 10.2118/93621-MS

D.R. Davies, SPE, R. Narayanasamy, SPE, B. Kristensen, and J.M. Somerville, SPE, Heriot-Watt University : 2008,Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective SPE 99878-PA

Aileen Pérez and Sergio Caicedo PDVSA-Intevep 2009; Figure 10 Schlumberger's DESP tools each for a different flow & Usage Profile


Feasibility Study of Dual "Backup" Electrical Submersible Pump Based on Risk Analysis, SPE-120889-MS

Totalfinaelf E&P Yemen ANW002 Dual ESP Completion Report, East Shabwa-Yemen

Novomet Multi reservoir production solutions, Information Handlet


Appendix

The studies were carried out with the help of a two-phase (oil and water) simulation of a 3D reservoir model using the EclipseTM 100 package. WellfloTM was used to model the vertical-lift performance for the produced fluids through the wellbore and the pump performance under the various reservoir conditions. The results obtained were transferred to the EclipseTM models in the form of vertical-flow-performance (VFP) tables. A detailed description of the model used as input for comparison of the EclipseTM, the WellfloTM and the analytical solutions is listed in Tables 1 and 2. Simulation results using the EclipseTM and WellfloTM programs were compared with appropriate analytical solutions where possible. WellfloTM can model only an SESP. A VFP table was generated for each ESP from WellfloTM . DESPs were modeled as two individual SESPs, the VFP tables being coupled together by use of the EclipseTM network option so that the flow performance of a DESP was reproduced. This approach was used for all cases apart from the water-coning application, where the fluids were produced to surface in separate streams. performance in the simulations.

Author Contact Details

Shashwat Agarwal, School Of Petroleum Technology, Pandit Deendayal Petroleum University.Mobile: +919408517517; +919415325798Email: [email protected]; [email protected]

mailto:[email protected]



Shamit Rathi, School Of Petroleum Technology, Pandit Deendayal Petroleum University.Mobile: +917878517529Email: [email protected]; [email protected]

Animesh Jain, School Of Petroleum Technology, Pandit Deendayal Petroleum UniversityMobile: +919428696131Email: [email protected];




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DESP