ESP challenges in an EOR project after breakthrough: An analysis of continuous improvement for ESP designs towards the reduction of OPEX

Waterflooding EOR projects are essential for a wide range of reservoirs worldwide, and the success of the method comes from its simple and relatively low-cost application, compared to other EOR options.¹ This is the case for the Ecuadoran field in this study, for which production started in 1975, injection pilots had been implemented progressively since 2017, and breakthroughs in production wells have been observed in several wells since 2020. 

In this sense, considering that we are now observing the behaviors of wells and reservoirs right after the breakthrough, it is necessary to rethink and evaluate the tools to address new constraints that had been found during dismantle and failure analyses (DIFAs). In a simple way, we are basically using ESPs as indicators of changes in the reservoir. Since the ESP equipment will be the first element that will be handling and dealing with the reservoir fluid, and will handle the fluid throughout the ESP lifespan, it is a very valuable source of information. If properly managed, it can help us understand the condition of, and any changes in, the reservoir. 

Data from several studies suggest that there can be a direct effect of fluid properties when mixing them.² Asphaltene precipitation may occur,³ and the mixing of incompatible water can lead to deposits4 or even an increase in solids production. 

Exposure to these fluid changes has caused adverse effects in standard ESP applications. Many analyses are performed in terms of reservoir behavior, geostatistics, pattern configuration, and cyclic injection techniques from a reservoir perspective in waterflooding projects. To date, there has been little discussion about what changes we can expect from the well fluid after the breakthrough and the techniques that should be readily available to keep producing effectively and accommodate the ESP to the conditions. 

The purpose of this article is to review recent findings from producing wells that had moved from a phase of no waterflooding injection to a phase of "after breakthrough" and the new surveillance technique used to track and understand the changes involved in the process. This article presents a different perspective of what to expect on a waterflooding project from the view of the production engineering challenges. The article outlines the key symptoms and examples for interpretation and a clear problem-solving path for each issue, aiming to extend ESP run life, which will translate into an OPEX reduction for the operator. 

STATEMENT OF THEORY AND DEFINITIONS 

For readers to understand the purpose of this study, it is necessary to introduce several terms. These terms include head derate factor, rate derate factor, and power derate factor, which are used as indicators of deviations. 

Head refers to the lifting of the pump. In other words, head is the height to which the fluid is raised/measured in feet (or meters). The head derate factor is a value between 0% and 200% theoretically. If refers to the deviation between the expected simulation operational head of the pump (taking in consideration viscous and gas conditions of the fluid) against the real flowing condition of the well. 

Rate refers to the total flow measured at surface conditions. The rate derate factor can take a value between 0% and 200% theoretically. A value of 100% means that the simulated conditions match exactly as the surface measured conditions. A value below 100% shows that the ESP is producing less than expected, so external conditions, such as a plug in the flow passages, stage wear, higher viscous properties, or higher free gas may exist. 

Power refers to the motor consumption. The power derate factor can also take a value from 0% to 200% theoretically. A value above 100% shows an abnormal overconsumption of the motor in terms of amps, compared to the operational condition. Current measured in amps is the value to be matched during the simulation.  

For the investigation in this article, to simplify the analysis, the head and rate derate factors are considered identical. Even if they are not, they are weighted equally by averaging them, since the external conditions affecting both factors are the same. 

Fig. 1 shows an example of an ESP curve, illustrating how the curves behave toward the production and what the derate factors represent. The value of the black arrows represents the value of the derate factor (expressed as a percentage).  

Fig. 1. Pump curve showing derate factors.

PROBLEM STATEMENT 

During the last year, an abnormal increase in failures related to jammed ESPs and mechanically damaged ESPs arose in the Ecuadorian field of this study. Fig. 2 shows the failure distribution in one year of those ESPs that lasted less than 900 days, both. Jammed and broken shafts had a 79% distribution. 

Fig. 2. Failure distribution.

Surprisingly, there was a particular relationship in these failures. During the investigation of each failure, it was seen that many of the failures shared a pattern in which the failure event occurred months after the water cut increased, related to the breakthrough event of the waterflooding. As shown in Fig. 3, 55% of the failures occurred after the producing well had a water immersion. 

Fig. 3. Percentage of wells that failed after the water immersion.

In addition to mechanical or jamming failures that occurred after the water immersion, electrical failures occurred. Fig. 4 shows the relationship between the failures and those wells that had water irruption prior to the failure.  

Fig. 4. Percentage distribution of wells that failed after the water immersion and the causes.

COMMON FAILURE MECHANISMS 

It is important to highlight that the failure mechanisms were segregated among jamming failures, mechanical failures, and electrical failures. 

Failure from jamming refers to those ESPs that did not have any broken component but in which the material accumulation was so intense that the ESP could not resume its normal operations. This contrasts with mechanical failure, where damage, such as broken shaft, occurred. Electrical failures in this paper refer to motor lead extension (MLE) failures particularly. 

Jamming failure. Well C-16 is an example of jamming failure. When retrieved, this ESP did not have any electrical or mechanical damage. However, neither attempt of starting up the ESP via a forced start-up procedure nor the performed circulation was effective, so the ESP had to be retrieved and replaced. The material contexture and composition found at the DIFA is shown in Fig. 5. Note how the material remains adhered to flow passages, even after a sandblasting process was applied to the stage. 

Fig. 5. Material retrieved from a well that failed due to jamming issues.

Mechanical failure. All the wells that fall under this category had a broken component inside the ESP string, either a coupling or most commonly a shaft. For this example, well X-117 was selected, Fig. 6.  

Fig. 6. Material retrieved from a well that failed due to broken shaft.

Electrical failure. With the accumulation of material in the stages, two effects occur. First, friction between the moving elements and the foreign material increases the working temperature at the pump. Second, since flow passages lose their flow capacity, the pump loses efficiency, and this is translated as an increase in temperature, as well. 

These two effects cause heat to be transmitted to other components of the ESP, such as the MLE, causing a deterioration of its mechanical integrity and thus its isolation capability. Finally, the ESP will fail, due to electrical failure. The results of high-temperature exposure are detailed in Fig. 7 from well X-68. 

Fig. 7. Material retrieved from a well that failed due to electrical failure.

Some of the stated failures are either related to sand or deposit production. The solid production from the reservoir also can be found in the accumulation of material in the well rat hole. Fig. 8 shows the production profile of the well, and Fig. 9 is the schematic of the material accumulation found after the ESP worked for 717 days. This case is important to highlight, since the material was accumulated above the depth of the production reservoir. 

Fig. 8. Production profile after breakthrough.

Fig. 9. Schematic of solid accumulation; a) Confirmed rathole prior to running the ESP; b) Confirmed material accumulation after 717 days of production; c) A sand bailer was used to retrieve a sample; and d) Rathole after running a cleaning BHA using junk mill.

BREAKTHROUGH SIGNATURE 

Frequently, these types of failures were observed to happen after an increase in water cut, drop in salinity, or increase in well productivity, shown as stable production with an increase in pump intake pressure (PIP). One example is shown in Fig. 10. In this case, the confirmation of water immersion into the production well was corroborated.  

Fig. 10. Common well behavior after breakthrough.

METHODOLOGY 

The described failure mechanisms gave us a hint of possible issues affecting the ESP after the breakthrough. However, the need to quantify the effects pushed the need to seek a new mechanism to track the ESP performance. 

To measure the progressive effect of foreign material or conditions affecting the ESP performance, derate factors were historically tracked and contrasted with downhole conditions and production data. Fig. 11 is an example of a well for which the historical derate factors show progressive decline as water immersion occurred in the well. As seen in the graph, a progressive overconsumption of the motor from 100% up to120% after one year is observed, while the head derate progressively drops from 98% to 62% in a period of 22 months. After the ESP was retrieved, these derate behaviors were understood, as deposits were found to have blocked the flow passage restricting the head capability. 

Fig. 11. Correlation between production data against derate factors.

RESULTS 

This strong tracking mechanism methodology enabled us to replicate the study in different wells, giving us two important opportunities. We are able to quantify and classify the type of problems observed after the breakthrough. Fig. 12 shows the repetitiveness of each cause of failure. 

Fig. 12. Distribution of causes of failures.

We can use this tracking mechanism methodology as a tool to provide preventive actions and recommendations. As variations of derate factors are identified, preventive measures can be put in place to mitigate them. These preventive methods are chosen, based on data from the well, such as chemistry surveillance and new saturate, aromatic, resin and asphaltene (SARA) analysis taken along the field. This method is shown in the example of Fig. 13, where head derate values in period A were 103%; in B were 85.5%; and in C were 60.8%. This alert triggered a deeper analysis into the well, which revealed that chemical treatment of the well, particularly the scale inhibitor treatment, was not reaching the ESP depth, as the capillary tube was plugged and no chemistry was inhibiting the fouling fluid of the well. 

Fig. 13. Example of tracking derate factor in producing wells as fluid condition changes.

ACTIONS TO BE TAKEN 

Preventive and corrective actions can be performed, based on the findings of this methodology applied postmortem or during ESP operation. Table 1 is a summary of preventive and corrective actions used in the field to avoid and mitigate issues.  

CONCLUSIONS 

The behavior of fluid properties after the immersion of water from waterflooding has changed the challengesin the studied field. New adverse conditions that previously were not present in the field were identified.The key to dealing with them is to identify the reservoirs and wells facing each problem so that each canbe solved appropriately and on time. 

Tracking historic derate factors is a strong tool to take preventive actions and understand the ESP performance. As seen in the examples, the presence of solid accumulation, asphaltenes or deposits causes the pump head to degrade, as the flow passages of the ESP get clogged, and less fluid can pass through. In terms of power consumption tracked by the current value, mainly solids and deposits will cause a representative increase of the power derate factor, since the motor will have to overcome the extra friction caused by this foreign material. It has been seen that when dealing with asphaltenes, this behavior will not necessarily occur in all cases and only head degradation occurs.  

FUTURE WORK 

Currently, these simulations are run manually by an engineer using software. Based on the importance of tracking the derate factors, a new logic is being investigated to encompass a wider well population. 

New investigations tracking fluid property changes are set in the field to study the phenomenon. An update in SARA analysis to perform fluid surveillance; chromatography studies to track gas composition changes; and an X-ray diffraction test from the solids collected from ESPs are being performed to classify those reservoirs with specific issues. The will also prepare production engineers to address the issues in those wells, in which the breakthrough has not yet occurred. 

ACKNOWLEDGMENTS 

The authors gratefully acknowledge the contributions of this investigation and support from their colleagues and partners. 

This article is based on a paper prepared for presentation at ADIPEC, held in Abu Dhabi, UAE, Oct. 2-5, 2023. 

REFERENCES 

1. Gede, G. A., H.R.D. Sutoyo and M. Bellout, et al, “Effects of well placement on CO2 emissions from waterflooding operation,” paper SPE-209565-MS, presented at the SPE Norway Subsurface Conference, Bergen, Norway, April 27, 2022. https:/doi.org/10.2118/209565-MS.
2. Akbarzadeh, K., A. Hammami, and A. Kharrat, A., et al, “Potential, asphaltenes—problematic but rich in potential, Oilfield Review, Summer 2007, pp. 22−42.
3. Li, C., “Reservoir simulation assessment for the effect of asphaltene deposition on waterflooding in B Oilfield,” paper IPTC-22974-MS, presented at the International Petroleum Technology Conference, Bangkok, Thailand, March1-3, 2023. https://doi.org/10.2118/IPTC-22974-MS. 
4. Andagoya, K., et al, “ESP run life increased by 230% using a small, customized device: The next step in flow assurance and chemical injection for ESP-lifted wells,” paper SPE-211213-MS, presented at ADIPEC, Abu Dhabi, UAE, Oct. 31−Nov. 3, 2022. https"//doi.org/10.2118/211213-MS.