SPE 141668

Poseidon Gas Handling Technology: A Case Study of Three ESP Wells in the Congo L. Camilleri, SPE, Schlumberger; L. Brunet and E. Segui, SPE, Total

Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Oil and Gas Show and Conference held in Manama, Bahrain, 6–9 March 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract In the Republic of Congo, the reservoir pressures in the Likalala and Kombi fields have decreased since production start-up and have dropped below the bubblepoint resulting in secondary gas caps. Consequently, the producing gas/oil ratio (GOR) and gas void fractions (GVFs) of the wells have increased. These fields are produced using electrical submersible pumps (ESPs); however, the drawdown has been limited by traditional ESP gas handling technology, which typically cannot handle GVFs higher than 40%. Total E&P Congo installed three ESPs with advanced helicoaxial pump technology in these two reservoirs. After nearly 2 years of operations on wells Likalala 106 and Kombi 102, production has stabilized and increased as a result of eliminating shutdowns and increasing drawdown. On the third well, Likalala 112, helicoaxial technology ensured that production targets were achieved despite unexpected high GOR and GVFs. This paper reviews these applications, focusing on the ESP and well outflow simulations, which demonstrate that the higher GVF handling capability of the pumps provides the technology needed to increase drawdowns. The paper includes analysis and review of well performance, from inflow through to facilities. It also reviews the in-situ GVF performance of the gas handling device with GVFs measurements as high as 80%. A head correction correlation is also matched to the field results providing users with a method for modeling future ESP applications with high GVF. Finally the downhole gas separator efficiency is reviewed and suggestions made on how future completions can achieve higher separation efficiencies. The results are used to provide a benchmark and design guidelines for future high GOR-ESP applications. Well and Field Introduction The three wells analysed are Likalala 106, 112 and Kombi 102. They are part of the KOMBI-LIKALALA–LIBONDO permit, which is operated by Total (65%) in partnership with ENI (35%). These reservoirs, which have faulted anticlinal structures, are located on the Congolese Albian-Cenomanian continental shelf. The fields are located offshore Pointe Noire in Congo and were placed on production in 1999. The fields consist of multiple disconnected layers that are characterized by oil-bearing zones, which are 10 m to 100 m thick with gas caps in some of the layers. The Albian and Cenomanian reservoirs are Sendji carbonates and Tchala sandstones, respectively, with porosities between 15% and 25% and permeabilities varying between 50 md and 5,000 md. The oil viscosity varies according to the layer between 1.5 cp in the Albian layers and up to several hundred cp for the Cenomanian layers. The wells considered in this paper are produced from Albian layers. Likalala production is exported through an 18-km multiphase flowline directly to the Kombi field where it is commingled with Kombi production and then exported through another multiphase flowline (16 km) to the Yanga processing platform. As a result of the multiphase flowlines, the ESPs are designed to generate the required export pressures, which vary between 35 barg and 25 barg on Likalala and Kombi, respectively. Depletion has led to secondary gas caps in both reservoirs. This factor, combined with the need to stop future downhole gas separation and maintain high drawdowns, identified a need for an ESP system that could handle high GVFs to enable the ongoing development of the Likalala-Kombi-Libondo permit. These are the main drivers that motivated TOTAL to initiate a field trial of the PoseidonTM helicoaxial ESP system. Completion Architecture All three wells have similar completion architectures with the sandface completions having a single horizontal drain. The notable difference between the wells is the length of the horizontal drains. Kombi 102 has a horizontal section that is nearly

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1,500 m long, whereas the Likalala 106 and 122 drains are 450 m and 700m long respectively. The horizontal drains are at similar vertical depths of approximately 1,100 m TVD, see TABLE 1 for details. The ESPs are set deep at nearly the same depth as the heel of the horizontal section. The upper completions are also identical (see Fig. 1) with the same shallow set packer and tubing subsurface safety valve providing the second mechanical barrier. The important point to note here is that gas separation and venting up the annulus is made via a gas-vent valve located in the packer. This valve is fitted on the same packer port as the cable feedthrough and the ESP power cable runs concentrically inside the vent valve. The gas flow path (see Fig. 2) is initially between the inside diameter (ID) of the valve and the OD of the power cable and then it passes into the casing through lateral portholes. The smallest flow passage is between the cable and the valve ID and can potentially limit gas flow and, therefore, gas separation efficiency, which in turn can increase the GVF at the pump intake. The ESP string configuration with the helicoaxial booster pump is the same for both wells and is detailed in Fig. 1. The key point is that both a gas separator and a helicoaxial pump are combined with a standard pump. All three wells use the same gas separator, helicoaxial pump and SN8500 pump which has mixed flow stages. The only notable difference is that Likala 112 has 179 stages of SN8500 whereas Likalala 106 and Kombi 102 have 153 stages of SN8500. Production History: Likalala Field and Well #106 and #112 The Albian Likalala development includes five producers and one injector. All the producers have horizontal sandface completions to optimize reservoir drainage and maximize the productivity index (PI). Both wells are completed in the same layer, A2, and use ESPs for artificial lift. During the initial production phase (before 2005), gas that vented up the well annulus was injected back into the production flowline at the surface, which meant that the flowline and annulus pressures were equal. This limited drawdown because pump intake pressure has to be greater than the wellhead casing pressure to maintain submergence. After 2005, the vented gas was connected to the flare to reduce the casing pressure to 20 bar and subsequently in 2008 to the current 14 barg. Because TOTAL plans to prevent flaring gas in this field, one option being considered is to stop separating and venting gas downhole. This plan will increase the GVFs in the ESP, which have decreased in recent years as a result of the dropping GOR. The production histories for both Likalala wells are shown in Fig. 3 and Fig. 4 with flowrate and flowing pressure trends. The reservoir is saturated, with the initial reservoir pressure equal to the bubblepoint. Initial production came from Wells #101, #102, and #110 with large drawdowns of 30 to 40 bar and flowing pressures between 40 and 50 barg, which were substantially below the bubblepoint of 127.5 bara. Furthermore, natural aquifer support in this reservoir is weak and water injection was not initiated until 5 years after first oil was produced, resulting in the creation of a secondary gas cap. As a result, when Well #106 was placed on production in 2005, it had a high initial GOR ranging from 150 Sm3/m3 to 200 Sm3/m3 which is nearly twice the solution GOR of 86 Sm3/m3 Well LKLM106, nearest to the only injector well, LKLM103, is located in the southern part of the field (see Fig. 6). This close proximity caused the GOR decrease that began at the end of 2006. The pressure wave from the injector initially increased the distance to the gas cap and subsequently stabilized the reservoir pressure, which further accelerated the drop in the GOR to reach values equal to Rs by late 2008. The injector’s pressure support, which was confirmed by the drop in GOR, motivated TOTAL to increase the drawdown on Well #106 and investigate an ESP solution that could handle the high GVFs expected at lower-flowing bottomhole pressures. An ESP with a Poseidon pump was installed in September 2006, and the drawdowns increased substantially. The result was a reduction in the flowing bottomhole pressures from around 40 barg to 27 barg and then to 23 barg in late 2008, which is shown in Fig. 3 together with the gain in production. Likalala 112 was an infield development well drilled in 2009. The target was the crest of the structure; however, its perforations are deeper to produce further away from the secondary gas capbased on the lessons learnt from previous wells. The initial GOR was nevertheless very high but subsequently stabilised at around 200 to 300 Sm3/D. A higher PI was achieved with Well #112 than #106 and this is in part due to the longer horizontal drain. Production History: Kombi Field and Well #102, Fig. 5 The Kombi field C1C5 reservoir, which is in the Albian and dolomitic sandstone, was developed with two producers and two injectors. Reservoir permeabilities are approximately 50 md and can reach 1 darcy in the sandstone layers. This higher permeability combined with a light, low-viscosity crude of 0.9 cp contributes to PIs that are higher in Kombi than in the Likalala A2 layer. Horizontal sandface completions with ESPs were used for all the wells to maximize reservoir drainage from a single offshore platform. Because the reservoir is saturated with the initial reservoir pressure equal to the bubblepoint, flowing bottomhole pressures are below the bubblepoint the moment wells are placed on production regardless of the drawdown that is applied. In addition, because natural aquifer support is weak in this reservoir, water injection pressure support was initiated early in this field, with the drilling of the first injector in 2000 (Well KOBM109) in the northern part of the field. The injected volumes, however, were insufficient to maintain reservoir pressure. Pressure support in the southern part of the field for Kombi #102 was initiated at the end of 2006 with injector KOBM110, which is 6 years after Well Kombi 102

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started producing (see Fig. 7). As a result, reservoir pressures dropped from an initial 90 bara to approximately 52 bara (see Fig. 8) during the first 5 years of production. This condition created a secondary gas cap, which is the main reason for high GORs of between 250 Sm3/m3 and 300 Sm3/m3. The GOR remained high until mid-2005 when the reservoir pressure stabilized and then increased slightly, reaching 57 bara by late 2007. As expected, the GOR dropped to approximately 60 Sm3/m3, which is the current stabilized formation GOR. The wellhead annulus pressure in Kombi #102 affected ESP submergence. At the end of 2002, the casing annulus pressure decreased from 45 barg to 30 barg and subsequently to approximately 25 barg. Unlike Likalala, this has not required flaring because the flowline export pressure is only 25 barg on Kombi. The trend of the reservoir pressure (Pr) and PI is shown in Fig. 8. During the initial production period up to June 2001, the well is in transient mode with both decaying liquid rates and flowing bottom-hole pressures. Consequently, productivity indexes (PIs) that were calculated at between 75 Sm3/D/bar and 100 Sm3/D/bar are ignored. The well then entered a pseudo-steady-state mode and the PI was calculated to be approximately 60 Sm3/D/bar. This value was used to plot the inflow performance relationship (IPR) curve shown in Fig. 9, which is based on the latest reservoir pressures of between 52 and 60 bara. Because reservoir pressures were physically measured four times during the life of the well, the PI calculation is reliable. Surveillance and Metrology Review Before discussing the analysis of the well and ESP performance, a review of the source of the analyzed data and the accuracy of that data is appropriate. The monitoring techniques were the same for both wells. - The surface flow rates were measured using a multiphase flowmeter connected to the wellhead flowline and operating at

wellhead pressures. Initially, the type of meter used was based on cross-correlation. Using this technique made obtaining accurate results difficult with the high GVFs that were present in the surface flowline associated with high GOR. As a result, surface metering was discontinued for approximately a year and new multiphase flowmeters were installed using mass-flowmeter technology without any cross correlation. This substantially improved accuracy.

- The multiphase flowmeter that was used only measures the GOR produced through the tubing, which was sufficient for the main purpose of the case study, which is to measure the GVF at the pump intake (after gas separation) and model the pump performance.

- For the purpose of measuring the gas separation efficiency, separate metering of annulus vented gas is required. Later on in the project, a vortex flowmeter was added to provide annulus gas measurement, which also provided a measure of the total formation GOR. A breakdown of these three GORs is shown in Fig. 10, Fig. 11 and Fig. 12.

- The ESPs were fitted with downhole gauges that measure the intake and the discharge pressure at the ESP depth. The gauges’ accuracy and resolution are ± 0.7 bar and 0.07bar, respectively. This metrology is sufficient for the steady-state analysis performed in the current case study.

Surface well testing is conducted between two and four times a month, depending on whether a setting such as ESP frequency has been changed in the well. Each test is conducted for a period of 12 hours, which represents between 30 and 60 times the tubing volume and provides good testing accuracy. This factor, combined with the fact that there is no fluid fallback in an ESP well, provides reliability that well tests reported are representative of the reservoir fluids being produced and entering the ESP. Furthermore, the relative high test frequency provides an accurate representation of the production trends. This surveillance technique has allowed direct measurement of the gas being produced through the Poseidon pump first stage and ESP without requiring an estimation and substraction of the gas being separated and vented up the annulus. This gas is reported as tubing GOR in the various graphs and is an important point in the validation of the GVF calculation at the first stage of the helicoaxial booster pump. The separate measurement of the tubing and annulus gas has also provided an opportunity to measure the efficiency of the downhole gas separator. Gas Separator Performance Analysis The GVF at the pump entry is a function of the tubing GOR and not the formation GOR, which is substantially greater. The difference between these two GORs is due to the gas vented up the annulus by the gas separator. A review of the gas separator performance is, therefore, essential to a holistic approach in producing high-GOR wells with ESP where gas venting is possible. Total gas separation efficiency refers to the combined natural and gas separator-induced separation efficiencies. The efficiency is thus defined by the following equation:

totalG

annulusGsepeff Q

Q!!

!=

where: QG-annulus = volumetric flowrate of free gas vented up the casing annulus. The flowrate is measured at the surface;

however, in this formula, it should be corrected to downhole ESP intake pressure and temperature using the gas formation volume factor (Bg).

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QG-total = volumetric flowrate of free gas at the ESP depth in the casing before gas separation. The flowrate is the sum of the gas in the tubing and in the annulus. Note, this flowrate needs to be calculated at downhole pressure and temperature conditions after taking into account that some of the gas may still be in solution and does not enter the equation.

The flowrate is calculated using the following equation:

( ) gsoiltotalG BRGORQQ !"!="

where:

Qoil = oil flow rate at stock tank conditions GOR = well producing GOR (also known as formation GOR, i.e. the sum of tubing and annulus GOR) Rs = solution GOR at the ESP intake pressure and temperature. Bg = gas formation volume factor at the ESP intake pressure and temperature; also obtained from PVT properties

Efficiencies were calculated and plotted versus time for the post-PoseidonTM installation period, and are shown in Fig. 10, Fig. 11 and Fig. 12 for the three wells. The efficiencies varied between 40% and 70%. While these plots confirm that reasonable separation efficiencies can be achieved, they do not show whether the gas separator is performing as expected. The paper by Lee on gas separator performance was selected to gain a better understanding of the physics underlying the performance of the gas separator as it contained laboratory test results of the same gas separator design used in these three wells, which has the model name “VGSA 70-150”. Furthermore, the efficiencies are reported in the same way, i.e. on the same basis of total separation (natural + mechanistic). Although these laboratory tests were performed using air and water, Lee did provide an explanation of the physics. The key performance curves developed during laboratory testing are shown in Fig. 13 and illustrate that the separation efficiency is primarily a function of two parameters, the GVF in the casing before separation and the in-situ liquid flow rate. To better compare laboratory tests to the field measurements made on Kombi 102 and Likalala 106, Lee’s laboratory test results were replotted in Fig. 14 with the liquid rate decoupled from the separator efficiency. The curves shown in Fig. 13 and Fig. 14, which are mathematically identical, illustrate that separation efficiency increases with increasing casing GVF as long as the liquid flow rate is below the limit for that efficiency curve. For example, assume the casing GVF is 50% and the liquid flow rate is less than 5,000 RB/D, then separation efficiency is expected to be 95%, however, if the liquid flow rate is 6,500 RB/D, then the expected separation efficiency is reduced to 75%. The in-situ liquid flow rates and the measured separation efficiencies for Wells Likalala 106 and Kombi 102 were plotted on the same graph as the VGSA S70-150 lab data in Fig. 14. For the purpose of interpretation, the results were separated into three zones, which are also shown in Fig. 14. - Zone 1: These are data from Well Kombi 102 only. Actual separation efficiencies of between 60% and 70% are only

slightly less than the expected laboratory efficiency of 75%. A possible explanation is that the liquid flow rates are 500 RB/D higher than the laboratory test limit. In this zone, there is a close match between field measurements and laboratory test results.

- Zone 2: These are data from Well Kombi 102 only. The measured separation efficiencies of approximately 40% are substantially lower than the laboratory test results of 85%. However, the liquid flow rates are between 1,000 RB/d and 1,500 RB/D, i.e., 50% greater than the limit required to achieve these efficiencies, which is a plausible explanation for the lower efficiencies.

- Zone 3: This includes both Kombi 102 and Likalala 106 data. The efficiencies are between 60% and 70%, but the laboratory test results indicate that at these GVFs, up to 90% efficiency can be achieved. The efficiencies are lower because the liquid flow rates are between 50% and 100% greater than the laboratory test limit.

Having conducted a comparison of field and laboratory performance, it is also necessary to check that the gas-vent valve in the packer is not acting as a constraint to the gas separation efficiency as this can also contribute to the lower than expected separation efficiencies. This review involved comparing the actual measured gas vented rates to the theoretical limits of the gas vent valve and this is illustrated in Fig. 15 and Fig. 16. In these graphs, the theoretical limit of the gas vent valve is calculated and plotted using Thornhill-Craver’s formulation for a square edge orifice valve. The gas vent valve’s smallest passage for the gas is the annulus between the cable OD and the ID of the valve. The area through the valve’s circulating portholes is actually greater and is therefore not considered. While the geometrical shape is not the same as a square edge orifice valve, the formula has been used in the absence of any other formulation to calculate the relationship between pressure drop and gas flowrate capacity. In addition to fluid property data for the gas, the key inputs to this formula are: - Downstream pressure; this is measured and is equal to the annulus pressure at the wellhead. As the packer is shallow set,

it can be assumed that they are equal as the gas gradient effect is negligible. - Pu (upstream pressure); this is not measured and is unfortunately unknown, however we do know that it must be less than the

pump intake pressure, otherwise pump submergence would be lost. As production is stable in the post-Poseidon installed time period, it has been assumed that the maximum value of upstream pressure is 5 bar less than the intake pressure.

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- Cd (Valve coefficient of discharge); Again this is unknown as most manufacturers do not provide tests for such valve types. Having said this, it is known that for a square edge orifice valve the maximum value is approximately 0.85. Therefore for a more tortuous path as presented by the gas vent valve, a maximum value of 0.75 has been considered.

Because Pu and Cd are unknown, extreme values have been considered in the Fig. 15 and Fig. 16 to bound the calculations. What these graphs illustrate is that even if the Cd is as low as 0.2, more gas than that measured can be vented as the upstream pressure can rise to provide the necessary differential pressure to vent gas. This is possible in these wells as there is a substantial difference between annulus pressure at the wellhead and at the intake. This analysis suggests that in wells Likala 106 and Kombi 102, the gas vent valve did not act as a constraint. On wells where the drawdowns are greater and the pressure difference between surface and intake in the annulus is smaller, this may not be possible and the gas vent valve may become a constraint and the analysis needs to be repeated. So while Cd for the gas vent valve remains unknown, these plots can be useful at the design stage to ensure that, in the worst case, gas can still be vented. The above analysis showed that reasonable separation efficiencies were achieved of between 60 and 70%. The gas separation efficiency of Likalala 112 was not analysed in the same way, although when measured and plotted in Fig. 12, it showed lower efficiencies of 50% to 60%. These field measurements are lower than tests achieved by Lee in the laboratory. The most plausible explanation is that liquid rates were too high for this gas separator. If calculations show that gas separation is adversely affected, then the alternative is to consider a completion that does not constrain gas separation. This could be achieved, for instance, by placing the packer below the ESP as explained by Camilleri et al (2010) or by considering a different type of gas-vent valve. Poseidon Field Results from Likalala 106 Before installing an ESP with a helicoaxial booster pump, the Likalala 106 well was produced using an ESP fitted with a gas handler and a gas separator. The well was producing approximately 500 Sm3/D (seeFig. 3); however, drawdown was limited by the already high GVF. The ESP was operating with an intake pressure of between 38 and 41 barg and an estimated GVF of approximately 50% at the ESP’s first stage. Because steady state conditions were not achieved, there is some uncertainty in these measurements and calculations. In September 2006, a helicoaxial booster pump was added to the ESP tool string that was run in the well. The booster pump consisting of 17 stages of the helicoaxial stage design shown in Fig. 17 and Fig. 18 was installed in the well. The results can be summarized as follows: - The ESP was operated for nearly a year—between September 2006 and August 2007—with a GVF exceeding 67% at the

ESP first stage, which reached a maximum of 70% (see Fig. 11). - The flowing bottomhole pressure was reduced by approximately 15 bar (see IPR curve in Fig. 19). This is an important

point because, although production only increased by 50 Sm3/d, had it not been possible to reduce the flowing bottomhole pressure, production would have decreased substantially as a result of the drop in reservoir pressure from 81 bara to 75 bara. The production loss that was averted is estimated at 200 Sm3/D between May 2006 and March 2007, which represents 40% of the nominal production.

Poseidon Field Results from Likalala 112 Likalala 112 was immediately placed on ESP production following drilling completion in 2009. Furthermore, based on the lessons learned from Likalala #106, a Poseidon booster pump was installed with the first ESP in 2009. As a result there is no “before” and “after” to compare production with and without a helicoaxial booster pump; however this well is noteworthy as it exhibited the highest GVF at Poseidon intake of 80%. This condition was confirmed with separate well tests of 12 hours each over a 3-day period and with NODAL* analysis, although production was unstable during this time with an oscillating wellhead pressure. Subsequently, the flowing bottomhole pressure stabilized at ~56 barg at 450 Sm3/D with a GVF of 70% and a stable production. ESP production would not have been possible without a Poseidon booster pump in this well because there was no drawdown condition which would have reduced the GVF below 40% to use an AGH instead of a Poseidon. Poseidon Field Results from Kombi 102 The Kombi 102 well exhibited high instability with the original ESP installation before fitting a helicoaxial booster pump to the ESP string, which was observed in several ways: - The wellhead pressure exhibited large oscillations (see Fig. 5 for the period before May 2006), showing pressure swings

of up to 25 bar. - The ESP current was also fluctuating substantially (see Fig. 20). - The GVF was estimated at between 40% and 50% at the ESP first stage. The uncertainty in the estimate is because well

instability made testing difficult. In January 2007, an ESP with a Poseidon booster pump was installed with the same configuration as Likalala 106 and the following results were observed: - Production parameters such as wellhead pressure were stabilized (see Fig. 20).

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- Stops and starts caused by gas locking were also eliminated, which increased the well uptime and thus increased production.

- The ESP was operated for nearly 3 months between January and March 2007 with a GVF exceeding 45% at the helicoaxial pump first stage and up to a maximum of 49% (see Fig. 10).

- The flowing bottom-hole pressure was reduced by between 8 and 10 bar as illustrated by the operating points on the IPR curve in Fig. 9, which increased production by 50%, from 600 Sm3/D to more than 900 Sm3/D.

The results from all three wells have been consolidated in TABLE 1 and TABLE 2, however the more interesting representation of the results is shown in Fig. 21, where GVF at the PoseidonTM intake is plotted against intake pressure. It has been known for a long time that ESP gas handling is improved with increased intake pressure and it is for this reason that the results are plotted versus intake pressure. It is most probable that the first quantitative explanation of the physics was published by Turpin et al. (1987) in which the authors correlated the pump performance to a factor !, also commonly referred to as the “Turpin Factor”, which is calculated using Eq. 1. Turpin concluded that when !>1, the pump suffers significant head degredation and eventually gas locks. The measurements from these three wells were therefore compared to GVF for ! equal 1 and 3. Fig. 21 shows that stable operation is achieved with ! = 3, even though there is head degredation as explained later in this paper.

! ! !"""!! !!!!!!!!!!"

Eq. 1 – empirical Correlation for ESP gas handling established by Turpin et al (1987). The numerator is also commonly known as the gas liquid ratio (GLR). In this equation pressure must be expressed in psi.

Theory on Head Degradation in Centrifugal and Helicoaxial Pumps Poseidon technology, as applied to ESPs, is a short section of 15 helicoaxial stages fitted to the suction side of the main standard centrifugal pump. The head generated by the helicoaxial booster and the main 159 or 179 stage SN8500 pump is shown in Fig. 22, which illustrate that the helicoaxial pump differential head represents less than 9% of the total water head generated by the pumping system deployed in the well. Evidently, then, the role of the helicoaxial pump is not to provide the required lifting pressure. So what is its role? The best explanation the authors found explaining the physics of helicoaxial centrifugal pump technology as applied to pumping high-GVF fluids is provided by Gulich. Although Gulich refers to helicoaxial pumps that are used in surface pumping applications where they are the main method for generating differential pressure in the process stream, the explanation of the physics is also applicable to ESPs. For ease of reference, a brief and simplified explanation follows. First, it is helpful to recap why traditional centrifugal pumps (i.e., non axial and non helicoaxial stages) generate less head in high-GVF fluids, which can ultimately lead to gas locking. The main reason for generating less head is phase segregation in the impeller flow path. This condition is analogous to the slip in multiphase flow through tubing. In a centrifugal pump, the centrifugal and coriolis forces induce phase separation because of the difference in body forces acting on the bubbles of free gas and liquid resulting from the difference in density. The free gas then accumulates in the low-pressure zone of the impeller. As a result, work transfer from the impeller to the fluid is impaired, which practically means that there is head loss relative to the impeller water curve. In extreme cases, large accumulations of gas at the impeller inlet lead to gas locking. Conversely, if the fluid is homogenous and GVF value is low, the pressure generated by the impeller is proportional to the mixture density and no head correction is required. Quasihomogenous mixtures exist at both low and high GVF values. At low GVF values, fine bubbles dispersed in liquid are entrained by the fluid and there is a little or no slip between the phases. This is known as bubbly flow. Likewise, at high GVF values, droplets of liquid carried along by a gas stream are represented as a homogenous flow model. This second flow regime is rare in ESP applications, and it is not considered in this case study. More important to the present discussion is the fact that as the GVF value increases, bubbly flow is no longer possible because the small bubbles coalesce to form larger gas accumulations leading to increased slip. Therefore, where free gas is present, the equation for the pressure generated by a

centrifugal pump needs to include a head correction factor as expressed in stgmhid h!Cgpp !!!=" Eq. 2.

stgmhid h!Cgpp !!!="

Eq. 2: Stage differential pressure at a given flowrate

where: pd = stage discharge pressure pi = stage intake pressure g = gravitational acceleration hstg = stage water head, obtained from factory test with water for the particular pump model

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"m = homogenous density, where # is the gas void fraction and is purely a function of the fluid pressure/volume/temperature (PVT) properties at the stage pressure. For ESP applications, PVT properties are calculated at the stage intake pressure, which is an acceptable approximation because the differential pressure across each stage is typically small when compared to the overall pressure drop across the entire pump. Homogenous density is defined by the equation "m= # "gas + (1- #) "liquid

# = GVF Ch = stage head correction, primarily caused by slip in the presence of free gas, and is a value between 0 and 1. Ch=1 for

a homogenous fluid and a low GVF. Ch<1 where there is head degradation caused by slip and a high GVF.

Note that stgmhid h!Cgpp !!!=" Eq. 2 assumes that fluid is incompressible across each stage (i.e., constant density). This is, of course, theoretically incorrect;

however, because the stage differential pressure is small (<0.5 bar in most cases), stgmhid h!Cgpp !!!=" Eq. 2 is an acceptable approximation as long as the density is recalculated at each stage so that incompressibility is not assumed as the fluid travels through a pump of say 159 stages as in this case study. If radial centrifugal and Coriolis forces can be reduced, then, based on the preceding explanation of the behavior of radial and mixed flow impellers in gaseous media, phase separation and the associated head degradation can also be reduced. Axial flow impellers have improved performance in the presence of free gas because centrifugal and Coriolis accelerations have opposing components and also because secondary flows contribute to better phase mixing. The helicoaxial impeller goes one step further, and, according to Gulich, “a helicoaxial impeller can be viewed as an axial impeller with a conical hub and, as a result, can handle any GVF” because, in addition to the axial impeller features, there is cross-channel mixing induced by the shape of the hub and secondary flows. Essentially, the shape of the impeller reduces phase separation (see Fig. 17 and Fig. 18). In addition the helicoaxial stage accelerates the fluid (both phases), which mitigates gas accumulation at the eye of the first impeller of the ESP and prevents possible gas locking. What the helicoaxial stage does not do is generate enough pressure to reduce the GVF before the fluid enters the main pump. The free gas is, therefore, still present in the main ESP. Furthermore, what has been observed on the two Likalala and Kombi wells is that unless a head correction is included, the calculated and measured pump differential pressures cannot be matched. Phase separation and gas accumulation is not the only cause for the poor gas handling capability of standard ESPs. The other issue is the negative pressure gradient caused by the corriolis force that induces reverse flow, which explains why the advanced gas handler (AGH) is built using impellers with mixed flow; i.e, similar to a standard ESP that has lower gas handling capabilities when compared to a helicoaxial booster pump. The AGH stages are fitted with recirculation ports in the impeller which allow liquid to reenter the flow passage in a low-pressure area and thereby entrain accumulated gas and transport it to the next stage, which is the feature that provides the enhanced gas-handling properties. As the AGH has mixed flow impeller geometry, the corriolis and radial forces are in the same direction; therefore these body forces combine to separate the two phases of gas and liquid as with standard ESP stages and thus, gas accumulates at the inlet. Despite the reentry liquid assisting its transport to the next stage, the gas still has to overcome the negative pressure gradient in the stage caused by the corriolis force. There is therefore a GVF limit at which point the liquid cannot entrain the gas and overcome the negative pressure gradient. For the AGH this limit is approximately 40% GVF, (see paper by Castro et al (1998)). The helicoaxial stage on the other hand does not have a negative pressure gradient because the corriolis and radial forces oppose each other, therefore the phase separation is not aggravated by the impeller. As a result, an ESP equipped with a Poseidon helicoaxial booster pump can handle GVF of 75% in steady state without gas locking and up to 100% in transient conditions such as gas slugs. Both the AGH and the helicoaxial booster pumps operate in the same way, i.e., they impart energy, which consists of momentum (i.e., 1/2 mV2 type energy). These pumps do not provide any substantial GVF reduction as the differential pressure they generate in downhole pumps is relatively small. It is the reverse flow characteristic (pressure gradient) of the impeller upstream of the main pump, which gives the main pump its ability to handle higher GVFs. The combination of reverse flow characteristic and kinetic energy contribution are the main contributing factors for which an ESP equipped with a Poseidon booster pump can handle a higher GVF than an ESP equipped with an AGH. ESP Performance Analysis While the field results from these three wells demonstrate that the helicoaxial booster pump stabilizes ESP production and eliminates gas locking at high GVF, there is no obvious explanation for the difference between the pump water curve and the measured pump differential head. When simulating the performance of the ESPs in the Likalala 106, 112 and Kombi 102 wells, a match with the intake and discharge pressure could only be achieved when head correction was applied. In actual fact, there is no known field calibrated model that would allow production engineers to estimate the number of stages required in the main pump and the motor horsepower rating required for a high-GVF application using a PoseidonTM helicoaxial pump combined with an ESP. Such a model would require an understanding of the head correction to be used at each stage as

defined by stgmhid h!Cgpp !!!=" Eq. 2. The only existing models are from laboratory tests, mostly with water and air. Pessoa et al (2001) provides a review of

8 SPE 141668

the literature on this subject and published test results with air and water for traditional ESP. More importantly, he identified the difference in head correction that occurs at each pump stage. Arnaudeau (1988) provides laboratory results for a helicoaxial surface pump, which differs from the downhole type by the fact that it operates alone to generate the required total head as opposed to as a booster, which has a larger diameter and operates at higher speeds (4500 to 8000 rpm). This second paper is interesting in that it shows the impact of absolute intake pressure on the head performance as well as GVF. The following is an explanation of how Ch was calculated to match the data measured on all three wells. A computer-based

model was built to perform the calculation in stgmhid h!Cgpp !!!="

Eq. 2 for each stage. The pressure generated by each stage was then summed (i.e., integration of stgmhid h!Cgpp !!!=" Eq. 2) to obtain the differential pressure across the entire ESP and to match the measured intake and discharge pressure using Eq. 3. When applying Eq. 3 it is important to recalculate the flowrate at each stage.

dnh!CgPPN

1stgmhid !" !!!=#

Eq. 3: Differential pressure across entire ESP with a total of N stages e.g. 174 stages = 159 stages of SN8500 + 15 helicoaxial stages

Eq. 3 shows integration from n=1 to n=174 because this is the total number of stages in the ESP with 15 helicoaxial stages plus the 159 SN8500 pump stages. The only unknown in Eq. 3 is Ch and it can be calculated for each well test simulation. However, before explaining how an equation for Ch was derived and matched to the data, a review must be performed of the assumptions that form the basis of Eq. 3 and the model used in this study. The assumptions include the following: - Steady-state conditions prevail. Indeed, Eq. 3 cannot model any transient conditions in the pump, such as surging. This

condition was believed to be satisfied in the post-Poseidon well tests because intake and discharge pressures were stable as shown in Fig. 23, Fig. 24 and Fig. 25 for Likalala 106.

- Gas does not go back into solution. This means that as the fluid travels through the pump and pressure increases, Rs remains constant and equal to the value at the pump intake. Bg does however change with pressure. This assumption is based on the fact that the residence time in the pump is too short for gas to go back into solution. The authors have observed in PVT laboratory experiments that gas can only go back into solution after long periods of time.

- Temperature was assumed to be constant through the pump and equal to the pump intake temperature. While this is not exactly true as the fluid will heat-up as it travels through the pump, the temperature increase is not large and it is affair approximation.

- A black oil model is used for the PVT calculations. This model is a common approximation in the industry and acceptable for the crudes in the Likalala and Kombi wells. On future case studies, a compositional model should be considered if lighter crudes with higher bubble points are being produced.

- The head generated by the ESP is based on the manufacturer’s catalogue water curve and no wear is assumed. On first inspection, this is a bold assumption; however, as is shown later in this paper, the calculated power absorbed by the ESP matches the measured power consumption, suggesting that the efficiency of the pumps in these two wells is as per the catalogue and there is little or no wear in the pump. Note that even where there is wear, this is the only assumption available because there is no known method for modeling pump wear.

- The head generated by the stage is calculated based on the total in-situ flow rate at the stage pressure, which is the sum of the insitu oil, water, and gas flow rates.

- Water was assumed to be incompressible. This, of course, is not exactly true, but, in view of the low water cuts in the well tests, the assumption has little impact on the results.

The next step was to advance a hypothesis on how to model the Ch at each ESP stage. The following known facts provided the starting point. - Condition 1 :Ch = 1 when # =GVF = 0 - Condition 2: !"!

!"! !!when # =GVF = 0

- Conditions 1 and 2 are consistent with the fact that for low GVF, Ch is assumed to be close to 1, although less than 1, because mixed flow impellers combined with a device that homogenizes the fluid are known to handle GVF up to 25% with little or no head degradation.

- As GVF increases, Ch decreases as shown in Gulich’s Figure 13.23. - Condition 3: !"!

!"! !!when # = #1, where #1 is some high value of GVF and the derivative is again zero as Ch reaches its

lowest value. This phenomenon has been observed in laboratory tests using air and water Based on these conditions and laboratory tests, such as Arnaudeau (1988), Ch is expected to behave as shown in Fig. 26, which can be modeled with a third-order polynomial such as Eq. 4.

SPE 141668 9

dcbaCh

+++= !!! 23

Eq. 4: Mathematical model for Ch where a, b, c and d are constants and # is the GVF

After substituting conditions 1 and 2, Eq. 4 can be simplified to become:

123 ++= !! baCh

Eq. 5: Ch after applying conditions 1 and 2

Two more conditions are required to define the coefficients “a” and “b”. Condition 3 is one of them and the other is used to fit the curve to match intake and discharge pressure using Eq. 3. The smallest Ch was chosen to occur at a GVF=0.75. This value was selected as laboratory tests have shown that this is the maximum steady state GVF for the Poseidon Booster pump. This provides the two additional conditions: - Condition 3: !"!

!"! !!when # = GVF= 0.75

- Condition 4: When # = GVF= 0.75, Ch = $ After substitution, the mathematical model used for regression fit is Eq. 6.

( ) ( ) 1133.5174.4 23 +!!!= "#"#hC

Eq. 6: Mathematical model for Ch used for regression fit

The value $ becomes the unknown that is solved for each well test simulated with the computer model. Seven well tests were simulated (two on Kombi 102, three on Likalala 106 and two on Likalala 112) and $ was obtained for each simulation. Note that $ is the lowest value of Ch based on this analytical model and is the unique characteristic for each curve of Ch in Fig. 28. An example of such a simulation with stage-by-stage calculation is shown Fig. 27, while Fig. 28 shows the head degredation model for all seven cases. On first inspection, the results shown in Fig. 28 are counterintuitive as the wells with higher GVF at the first stage show less head correction. Further analysis of $ is required to understand the underlying trends. A review of the literature shows that gas handling is a function of not only GVF, but also of: - Pump speed - Absolute intake pressure - Density satio between liquid and gas phases - Operating point on the pump curve relative to the best efficiency point (BEP) To investigate these dependencies, bubble graphs of $ were analysed for the seven cases and two meaningful graphs were retained and are shown in Fig. 29 and Fig. 30. The conclusions drawn were that there is a strong dependency on pump speed and a secondary dependency on pump operating point relative to the BEP. Interestingly, the test data published by Pessoa et al (2001) showed that gassy performance is best at flowrates greater than BEP, whereas the seven tests showed that head degredation is minimum just below BEP. Although other factors may be affecting this observation, the data are insufficient to draw any hard conclusions. Furthermore, the lack of correlation with density ratio and intake pressure does not mean that there is no dependency, but rather that there is probably insufficient data with these seven tests to establish a relationship and one should continue to take such measurements in future tests. In addition to matching ESP intake and discharge pressures using Eq. 3, a match of the calculated and measured power consumption was also performed. The same stage-by-stage method was used to calculate the power consumed by the ESP using Eq. 7.

( )! "

#=174

1

_$$ CppqESPPower idt

Eq. 7: Power consumed by ESP without constants for units

10 SPE 141668

Where: qt is the total in-situ stage flow rate (i.e., oil plus water plus gas rates) % pump efficiency at rate qt C% pump efficiency degradation caused by GVF With no other available data, the calculated power is based on the assumption that the coefficient of head and efficiency degradation are equal. This assumption was also made by Gulich. As shown in TABLE 2, the power calculated by this method matches the measured power to within 10% on most cases, which is an excellent match considering the accuracy of well testing and possible errors in calculating power based on current due to a lack of measured voltage. On the Likalala 112 well, there was a greater difference of up to 19% and it is believed that this is due to the fact that the measured power is less accurate due to the low-load factor. The power match further corroborates that Eq. 6 provides a holistic approach for modeling the ESP system in high-GVF conditions. The proposed correlation for head degradation remains a hypothesis, and though strong, it needs to be confirmed or refuted with further well test simulations. As Poseidon applications gain wider acceptance in the industry, further tests need to include other ESP stage geometries and other crude properties to either corroborate or refute the hypothesis for the head degradation correlation. Each stage type (geometry) could conceivably have its own head degradation curve in the same way that every pump has its own head-flow curve. To develop this knowledge base, future applications must be equipped with good surface well testing measurement facilities and accurately measure intake and discharge pressures. In the meantime, the correlation provides a good starting point for future PoseidonTM designs, especially those that include mixed flow impellers similar to the SN8500. Conclusion

• The case studies demonstrate that a PoseidonTM Helicoaxial pump enables ESP applications with GVF at the Helicoaxial Booster pump of up to 80%, although it should be noted that stable operation was only achieved with GVF up to 70%.

• In addition to being a function of the GVF fraction, pump performance was found to be dependant on absolute intake pressure.

• It is possible that the pump performance is also dependent on rotating speed and operating point relative to the best efficiency point, however these last factors would need to be verified with additional field testing.

• The helicoaxial pump has stabilized production and eliminated costly shutdowns. This pump has already increased production, which is a function of the up-time, and is therefore expected to also increase pump run lives.

• On wells Likalala 106 and Kombi 102, drawdown and thereby production has increased as a result of the Poseidon pump. On Likalala 112, ESP production in high GVF conditions was made possible.

• Following the results of this field study, TOTAL installed three more Poseidon helicoaxial booster pumps in other operations around the world and has plans for further installations. These installations will enable more ESP simulations and testing of the helicoaxial pump’s GVF operating range and the head degradation hypothesis advanced in this paper.

• This case study and, more importantly, the benchmarking of equipment performance for use in future applications was made possible by data availability in its largest sense, which includes both gauge and flowmeter deployment, as well as methods for data collection and storage.

• High-GOR ESP applications require a holistic approach that takes into consideration the reservoir, completion, surface facilities, and the artificial lift method as illustrated by the analysis in this paper.

References - Arnaudeau, M.P., 1988. Development of a Two-Phase Oil Pumping System for Evacuating Subsea Production without

Processing Over a Long Distance: Poseidon Project. Paper OTC 5648, presented at the 20th Annual OTC in Houston, 1988.

- Camilleri, L.A.P., Banciu, T., and Ditoiu, G. 2010. First Installation of 5 ESPs Offshore Romania - A Case Study and Lessons Learned. Paper SPE 127593 presented at the SPE Intelligent Energy Conference and Exhibition held in Utrecht, The Netherlands, 23–25 March.

- Castro, M., Pessoa, R., and Kallas, P., 1996. Successful Test of New ESP technology for Lake Maracaibo of Gassy Oil Wells, OTC 8867, presented at the 1998 Annual Offshore technology Conference in Houston.

- Gulich, J.F., Centrifugal Pumps, Springer, Chapter 13.2

- Woon Y. Lee, Schlumberger, ,ESP Gas Separator Performance Evaluation and Application Guideline, presented at Houston SPE ESP Workshop

SPE 141668 11

- Pessoa, R. and Prado, M., 2001, Two-Phase Flow Performance for Electric Submersible Pump Stages, SPE 71552 presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans.

- Turpin, J.L., Lea, J.F. and Bearden, J.L., 1987 Gas-Liquid Flow Through Centrifugal Pumps – Correlation of Data, Proceeding of Third International Pump Symposium, 1987.

TABLE 1 WELL PERFORMANCE SUMMARY

12 SPE 141668

Fig. 1 – ESP completion architecture and ESP string design

Fig. 2 – Gas vent valve fitted to packer with illustration of gas path. Power cable is not shown on the drawing but it is

concentric to the valve.

!"#$%&'(#)*+'*,-*'#*.-*/+"

0+1*+'*2.*'#*34*/+" !"#$%&'(#)*+'*,-*'#*.-*/+"

0+1*+'*2.*'#*34*/+" !"#$%&'(#)*+'*,-*'#*.-*/+"

0+1*+'*2.*'#*34*/+" !"#$%&'(#)*+'*,-*'#*.-*/+"

0+1*+'*2.*'#*34*/+"

2 !"#$%&'()%&*+

3 ,--$&%.*%/'0"#'12+'3456'7).'!"#$%&

, 0"#80"+1)9*'0)1*/:'7)-;*

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- F)%>$%&'G$@@-*

5

H0IJ8'I".@'/:@*'0GD5KK'2%')--'L'=*--?8'M5B'?/)&*?'2%'FNF'MKO')%>'N2.#$'MKP'8'MQL'?/)&*'2%'FNFMMP8'I2?*$>2%'I".@'05K8BK'''RM5'?/)&*?'21'<*-$92)E$)-'."-/$@<)?*'@".@S8'T2/)+:'U)?'0*@)+)/2+'8'7U0,'0QK8MBK

6 5OP'0*+$*?'V2/2+

7 H0I'&)"&*'R$%/)A*')%>'>$?9<)+&*'@+*??"+*S

8 W<*.$9)-'X%Y*9/$2%'0"#

9:2*;*9:3W2%/+2-'-$%*?'12+'9<*.$9)-'$%Y*9/$2%Z'?"#8?"+1)9*'?)1*/:';)-;*')%>'&)?';*%/';)-;*

Fig. 3 Likalala 106 production history illustrates how the Poseidon pump reduces flowing pressure from 40 to 26 barg

!"#$%&'()(*+*,)-./+0#1*2')"'+'$)3+*4/')#$%(.5+0%6

7*+*)8%/',)3+%##'()5%//'5+069)(*+*

:!:);<)4*$9

:!:)=>)4*$9

14 SPE 141668

Fig. 4 Likalala 112 production history, water cut is not shown as it is less than 2% throughout this production period. Production was achieved with very high GOR.

SPE 141668 15

Fig. 5 Kombi 102 production history illustrates slugging symptoms with oscillating wellhead pressure prior to Poseidon pump installation as well as how the multiphase pump

enabled stabilization of drawdown, thereby increasing liquid rate.

Liquid (sm3/d)

GOR formation(sm3/m3)

Frequency (Hz)

WellheadPressure( Bar)

Wellhead Csg(Annulus) Press(bar)

Pump IntakePressure (bar)

Water Cut

$ $ $$ $ $ $ $

$ $ $ $

$$ $ $$

$ $ $ $$

$ $ $ $

!"#$%&'()

Liquid (sm3/d)

GOR formation(sm3/m3)

Frequency (Hz)

WellheadPressure( Bar)

Wellhead Csg(Annulus) Press(bar)

Pump IntakePressure (bar)

Water Cut

$ $ $$ $ $ $ $

$ $ $ $

$$ $ $$

$ $ $ $$

$ $ $ $

Liquid (sm3/d)

GOR formation(sm3/m3)

Frequency (Hz)

WellheadPressure( Bar)

Wellhead Csg(Annulus) Press(bar)

Pump IntakePressure (bar)

Water Cut

$ $ $$ $ $ $ $

$ $ $ $

$$ $ $$

$ $ $ $$

$ $ $ $

!"#$%&'()

Fig. 6 Likalala contour map of Albian A2

Fig. 7 Kombi contour map of Albian C1C5

!"!#$%%&

!"!#$%'(

!"!#$%')

WOCiWOCi

500m

KOFKOF--11

KOBM1KOBM1--1010

KOBM1KOBM1--09G09G

KOBM1KOBM1--0101

KOBM1KOBM1--02G02G

WOCiWOCi

500m

KOFKOF--11

KOBM1KOBM1--1010

KOBM1KOBM1--09G09G

KOBM1KOBM1--0101

KOBM1KOBM1--02G02G

SPE 141668 17

Fig. 8 Kombi 102 reservoir pressure (Pr) and PI trends

Fig. 9 Kombi 102 IPR curve and ESP operating points

0

10

20

30

40

50

60

70

80

90

100

0 300 600 900 1200 1500 1800 2100 2400 2700 3000

Liquid Flowrate (Sm3/d)

Pres

sure

(Bar

a)

Nov 02 to May 03, Pr ~ 60 BaraMay 07 to Aug 08, Pr ~ 52 BaraOct-99Nov-99Feb-03Apr-04Nov-07

!"#$% !&'#()&*

!&'+$% !&'#()&*

Reservoir pressure:-Original Pr = 98 bara-Pr < Pb = 90 bara , hence high GOR -Reservoir pressure dropped to 52 bar in 2005 and, since, has increasing following water injection support

0

10

20

30

40

50

60

70

80

90

100

0 300 600 900 1200 1500 1800 2100 2400 2700 3000

Liquid Flowrate (Sm3/d)

Pres

sure

(Bar

a)

Nov 02 to May 03, Pr ~ 60 BaraMay 07 to Aug 08, Pr ~ 52 BaraOct-99Nov-99Feb-03Apr-04Nov-07

!"#$% !&'#()&*

!&'+$% !&'#()&*

Reservoir pressure:-Original Pr = 98 bara-Pr < Pb = 90 bara , hence high GOR -Reservoir pressure dropped to 52 bar in 2005 and, since, has increasing following water injection support

18 SPE 141668

Fig. 10 Kombi 102 post-Poseidon GVF and GOR, showing a maximum GVF of 48%

Fig. 11 Likalala 106 post-Poseidon GVF and GOR illustrating a maximum GVF of 68%

SPE 141668 19

Fig. 12 Likalala 112 post-Poseidon GVF and GOR illustrating a maximum GVF of 80%

Fig. 13 Gas separator performance laboratory test results using air and water

VGSA S70-150 Performance Curve for % Free Gas by Volume After Total Separation

0

20

40

60

80

100

0 5000 10000 15000Liquid Flow Rate (BPD)

% F

ree

Ga

s by

Vo

lum

e B

efo

re

An

y S

epar

atio

n 5%10%15%20%

20 SPE 141668

Fig. 14 Gas separation performance

Fig. 15 Comparison of theoretical and actual gas rate through gas vent valve for Likalala well 106

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1GVF in Casing (before Gas Separation)

Dow

nhol

e Li

quid

Flo

w Q

l = Q

o +

Qw

(rbp

d)

0

10

20

30

40

50

60

70

80

90

100

Tota

l Gas

Sep

arat

ion

Eff.

(%)

Max Liquid Rate for GVFout = 5% Max Liquid Rate for GVF out = 20%Likalala - Liquid Rate (rbpd) Kombi- Liquid Rate (rbpd)Eff (GVFo=5%) Eff (GVFo=20%)Likalala - Gas Separator Eff. (%) Kombi - Gas Separator Eff. (%)

1 2 3

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1GVF in Casing (before Gas Separation)

Dow

nhol

e Li

quid

Flo

w Q

l = Q

o +

Qw

(rbp

d)

0

10

20

30

40

50

60

70

80

90

100

Tota

l Gas

Sep

arat

ion

Eff.

(%)

Max Liquid Rate for GVFout = 5% Max Liquid Rate for GVF out = 20%Likalala - Liquid Rate (rbpd) Kombi- Liquid Rate (rbpd)Eff (GVFo=5%) Eff (GVFo=20%)Likalala - Gas Separator Eff. (%) Kombi - Gas Separator Eff. (%)

1 2 3

0

20

40

60

80

100

120

140

160

180

200

0 5 10 15 20 25 30

Gas

Rat

e (Sk

m3/

d)

Downstream Pressure (bar)

LIKALALAGas Rate Through Gas Vent Valve

GVV ID = 1.625", Cable OD = 1.333"

Upstream Pressure = 28 barg, Cd = 0.75

Measured Operating Points

Upstream Pressure=24 barg, Cd=0.2

Upstream Pressure = 24 barg, Cd = 0.2

SPE 141668 21

Fig. 16 Comparison of theoretical and actual gas rate through gas vent valve for Kombi well 101.

Fig. 17 Comparison of helicoaxial and mixed-flow impeller flow paths

0

50

100

150

200

250

0 10 20 30 40 50

Gas

Rat

e (S

km3/

d)

Downstream Pressure (bar)

KOMBIGas Rate Through Gas Vent Valve

GVV ID = 1.625", Cable OD = 1.333"

Upstream Pressure = 40 barg, Cd=0.75

Measured Data Points

Upstream Pressure = 24 barg, Cd=0.2

Upstream Pressure = 40 barg, Cd =0.2

22 SPE 141668

Fig. 18 Poseidon pump stage cutaway

Fig. 19 Likalala 106 IPR curve and ESP operating points

Pr measured at 81.3 bara July 2006

0

10

20

30

40

50

60

70

80

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800

Liquid Flowrate (sm3/d)

Pres

sure

Pw

f (ba

ra)

2008

Dec-07

Early 2007

Early 2006

WC=0% & Pr=81 bara

WC=20% & Pr = 81 bara

WC=20% & Pr =75 bara

Pr measured at 81.3 bara July 2006

!"#$% !&'#()&*

!&'+$%!&'#()&*

Reservoir pressure:-Original Pr = 127 bara-Reservoir pressure is relatively stable based on offset well data which have pressures between 74 and 88 bara measured recently in Nov 07

Pr measured at 81.3 bara July 2006

0

10

20

30

40

50

60

70

80

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800

Liquid Flowrate (sm3/d)

Pres

sure

Pw

f (ba

ra)

2008

Dec-07

Early 2007

Early 2006

WC=0% & Pr=81 bara

WC=20% & Pr = 81 bara

WC=20% & Pr =75 bara

Pr measured at 81.3 bara July 2006

!"#$% !&'#()&*

!&'+$%!&'#()&*

Reservoir pressure:-Original Pr = 127 bara-Reservoir pressure is relatively stable based on offset well data which have pressures between 74 and 88 bara measured recently in Nov 07

!"#$% !&'#()&*

!&'+$%!&'#()&*

Reservoir pressure:-Original Pr = 127 bara-Reservoir pressure is relatively stable based on offset well data which have pressures between 74 and 88 bara measured recently in Nov 07

SPE 141668 23

Fig. 20 Kombi 102 before and after Poseidon pump installation comparison of current and wellhead pressure

Fig. 21 Consolidated results for the three wells with seven measurements of GVF at the Poseidon pump intake. A Turpin

factor of three is achieved in two cases. Bubble size is the head degredation at a GVF of 75% as explained in Eq. 6 and listed in TABLE 2.

!"#$%"&'$(")*$+&,+(-.//.-)$+

0#-"%&'$(")*$+&,+(-.//.-)$+

!"#$%"&'$(")*$+&,+(-.//.-)$+

0#-"%&'$(")*$+&,+(-.//.-)$+

!"#$%&'()*+,#'-'.

!"#$%&'()*+,#'-'/

24 SPE 141668

Fig. 22 Water head curve at 60 Hz for SN8500 with 159 stages and PoseidonTM booster pump with 15 helicoaxial stages

illustrating that the head generated by the PoseidonTM pump is very small relative to the main pump.

Fig. 23 Likalala 106 zoom-in on gauge data at 60% GVF

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

27/2

/08

23:5

8

28/2

/08

1:10

28/2

/08

2:22

28/2

/08

3:34

28/2

/08

4:46

28/2

/08

5:58

28/2

/08

7:10

28/2

/08

8:22

28/2

/08

9:34

28/2

/08

10:4

6

28/2

/08

11:5

8

28/2

/08

13:1

0

28/2

/08

14:2

2

28/2

/08

15:3

4

28/2

/08

16:4

6

28/2

/08

17:5

8

28/2

/08

19:1

0

28/2

/08

20:2

2

28/2

/08

21:3

4

28/2

/08

22:4

6

28/2

/08

23:5

8

Pres

sure

(bar

g) &

Tem

pera

ture

(deg

C)

Intake Pressure Discharge Pressure Intake Temperature Motor Temperature

SPE 141668 25

Fig. 24 Likalala 106 zoom-in on gauge data at 50% GVF

Fig. 25 Likalala 106 zoom-in on gauge data at 48% GVF

10

20

30

40

50

60

70

80

90

100

110

120

130

140

15013

/8/0

8 0:

00

13/8

/08

1:12

13/8

/08

2:24

13/8

/08

3:36

13/8

/08

4:48

13/8

/08

6:00

13/8

/08

7:12

13/8

/08

8:24

13/8

/08

9:36

13/8

/08

10:4

8

13/8

/08

12:0

0

13/8

/08

13:1

2

13/8

/08

14:2

4

13/8

/08

15:3

6

13/8

/08

16:4

8

13/8

/08

18:0

0

13/8

/08

19:1

2

13/8

/08

20:2

4

13/8

/08

21:3

6

13/8

/08

22:4

8

Pres

sure

(bar

g) &

Tem

pera

ture

(deg

C)

Intake Pressure Discharge Pressure Intake Temperature

Motor Temperature Motor Frequency (Hz) Tubing head pressure (bar)

Flowline Pressure (bar)

0102030405060708090

100110120130140150

20/3

/07

1:00

20/3

/07

2:12

20/3

/07

3:24

20/3

/07

4:36

20/3

/07

5:48

20/3

/07

7:00

20/3

/07

8:12

20/3

/07

9:24

20/3

/07

10:3

6

20/3

/07

11:4

8

20/3

/07

13:0

0

20/3

/07

14:1

2

20/3

/07

15:2

4

20/3

/07

16:3

6

20/3

/07

17:4

8

20/3

/07

19:0

0

20/3

/07

20:1

2

20/3

/07

21:2

4

20/3

/07

22:3

6

Pres

sure

(Bar

)

Pump Intake Pressure (bar) Pump Discharge Pressure (barg)

26 SPE 141668

Fig. 26 Head degredation model to explain mathematical formula (not actual data)

Fig. 27 Example of regression fit showing how head degredation varies for each stage

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!"#$%&%"#'2)'''''''''''''''''',*-#'! +./0'+'1

!"#$%&%"#'3)'''''''''''''''''',*-#'! +./0'+'1456

SPE 141668 27

Fig. 28 Summary of all head degredation regressions

TABLE 2 SUMMARY OF RESULTS OF SEVEN REGRESSION SIMULATIONS

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'(")

*+$%,-

%"#.

28 SPE 141668

Fig. 29 Illustrates dependence of head degredation on frequency. Bubble size is the average liquid-to-gas density ratio for

which there is no dependency.

Fig. 30 Illustrates dependence of head degredation on pump operating point, showing how the most efficient operation seems

to be slightly below BEP. Bubble size is the average liquid-to-gas density ratio, which does not seem to effect operation.