First Application of Rigless Electrical Submersible Pump Technology in the Gulf of Mexico

Abstract An operator planned to install ESPs to overcome high water cut and minimize the gas supply risk for a gas lift completion at a platform in the Gulf of Mexico. The platform is an oil collection point and its continuous operation is essential during any rig-assisted interventions. To maintain platform operation, three wells were selected for deployment of rigless electrical submersible pump (ESP) replacement systems to avoid the future use of a workover rig. The challenge was to allow a single-trip ESP deployment using the crane facilities with existing height limitations. A special surface connection system was designed to allow long ESP sections to connect under pressure at the wellhead. The technology is based on a propriotery system and method of connecting long strings at the surface using a surface lubricator and an adapted deployment stack. The system elements are located between the pump intake and protector seal sections of a standard ESP string that can easily and economically sourced in most locations. This new technology reduces the number of wireline/slickline runs needed, and the system features allow verification of mechanical connection integrity at the surface prior to deployment in the well. The successful deployment and commissioning of a rigless ESP replacement system in the SM 130 A-26 well in the Gulf of Mexico was completed in October 2019 without incident. Prior to the deployment of the rigless ESP replacement system, it was decided to perform hydraulic stimulation operations to improve the well productivity. This operation resulted in higher than expected well inflow with increased water cut. At the time of writing this paper, the ESP system had recently failed to start due to stuck pump (possibly scale related). Due to the ability to perform a rigless system upgrade for the unanticipated well inflow conditions, the operator is planning for the first rigless replacement of the existing ESP to achieve higher flow rate during the last quarter of 2021. The successful deployment of the alternative ESP deployment technology demonstrated the potential to improve the economics of the existing production facilities by reducing production deferment, minimizing health, safety, and environment (HSE) exposure; and improving the asset value. This paper discusses the engineered solution and application of the technology required to deploy long ESP strings, modifications required for the specific well conditions, and the lessons learned during the first successful deployment of rigless ESP technology in the Gulf of Mexico. Due to the performance and capability demonstrated in the first successful installation, Talos Energy has recently installed its second rigless ESP replacement system in a recompleted zone and is planning for installing its third system in the SM 130 field in 2022.

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Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

10.2523/iptc-21837-ms ◽

2021 ◽

Author(s):

Mohd Hafizi Ariffin ◽

Muhammad Idraki M Khalil ◽

Abdullah M Razali ◽

M Iman Mostaffa

Keyword(s):

New Technology ◽

Lessons Learned ◽

Oil Fields ◽

Submersible Pump ◽

Large Space ◽

Gas Well ◽

Wellhead Pressure ◽

Artificial Lift ◽

Electrical Submersible Pump ◽

Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

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The Successful Use of Both Kinetic Hydrate and Paraffin Inhibitors Together in a Deepwater Pipeline with a High Water Cut in the Gulf of Mexico

10.2118/93158-ms ◽

2005 ◽

Cited By ~ 9

Author(s):

T.A. Swanson ◽

M. Petrie ◽

T.R. Sifferman

Keyword(s):

Gulf Of Mexico ◽

High Water ◽

High Water Cut ◽

Water Cut

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Fieldwide Application of Autonomous Inflow Control Valve in Increasing the Field Recovery in One of the Matured Fields in the Sultanate of Oman: Case Study

10.2118/208179-ms ◽

2021 ◽

Author(s):

Salim Buwauqi ◽

Ali Al Jumah ◽

Abdulhameed Shabini ◽

Ameera Harrasi ◽

Tejas Kalyani ◽

...

Keyword(s):

Control Valve ◽

Oil Production ◽

Horizontal Wells ◽

High Water ◽

Lessons Learned ◽

Water Production ◽

Sultanate Of Oman ◽

Well Performance ◽

Reservoir Conditions ◽

Water Cut

Abstract One of the largest operators in the Sultanate of Oman discovered a clastic reservoir field in 1980 and put it on production in 1985. The field produces viscous oil, ranging from 200 - 2000+ cP at reservoir conditions. Over 75% of the wells drilled are horizontal wells and the field is one of the largest producers in the Sultanate of Oman. The field challenges include strong aquifer, high permeability zones/faults and large fluid mobility contrast have resulted that most of the wells started with very high-water cuts. The current field water cut is over 94%. This paper details operator's meticulous journey in qualification, field trials followed by field-wide implementation and performance evaluation of Autonomous Inflow Control Valve (AICV) technology in reducing water production and increasing oil production significantly. AICV can precisely identify the fluid flowing through it and shutting-off the high water or gas saturated zones autonomously while stimulating oil production from healthy oil-saturated zones. Like other AICDs (Autonomous Inflow Control Device) AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICVs performance is superior due to its advanced design based on Hagen-Poiseuille and Bernoulli's principles. This paper describes an AICV completion design workflow involving a multi-disciplinary team as well as some of the field evaluation criteria to evaluate AICV well performance in the existing and in the new wells. The operator has completed several dozens of production wells with AICV technology in the field since 2018-19. Based on the field performance review, it has shown the benefit of accelerating oil production as well as reduction of unwanted water which not only reduces the OPEX of these wells but at the same time enormous positive impact on the environment. Many AICV wells started with just 25-40 % water cut and are still producing with low water cut and higher oil production. Based on the initial field-wide assessment, it is also envisaged that AICV wells will assist in achieving higher field recovery. Also, AICV helped in mitigating the facility constraints of handling produced water which will allow the operator continued to drill in-fill horizontal wells. Finally, the paper also discusses in detail the long-term performance results of some of the wells and their impact on cumulative field recovery as well as lessons learned to further optimise the well performance. The technology has a profound impact on improved sweep efficiency and as well plays an instrumental role in reducing the carbon footprint by reducing the significant water production at the surface. It is concluded that AICV technology has extended the field and wells life and proved to be the most cost-effective field-proven technology for the water shut-off application.

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NEW TECHNOLOGY INTEGRATION OF REAL TIME OBM BOREHOLE IMAGES AND FORMATION SAMPLING WHILE DRILLING. LESSONS LEARNED IN CHALLENGING DEEPWATER GULF OF MEXICO ENVIRONMENTS

10.30632/spwla-5038 ◽

2020 ◽

Author(s):

◽

Wilson Pineda ◽

Rana Elghonimy ◽

Milad Saidian ◽

Jennifer Wadsworth ◽

...

Keyword(s):

Technology Integration ◽

Gulf Of Mexico ◽

Real Time ◽

New Technology ◽

Lessons Learned

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Evaluating Alternate Artificial Lift Methods in the Niger Delta

10.2118/208262-ms ◽

2021 ◽

Author(s):

Priscilla Enwere ◽

Ademola Amusa ◽

Oluwafemi Olominu ◽

Nchekwube Lazson ◽

Emmanuel Mbonu ◽

...

Keyword(s):

Niger Delta ◽

Selection Criteria ◽

Selection Criterion ◽

Network Models ◽

Submersible Pump ◽

Artificial Lift ◽

Electrical Submersible Pump ◽

Water Cut ◽

Surface Production ◽

Gas Lift

Abstract Gas lift is currently being utilized as the artificial lift system in OML Z, this has been so for the last thirty years. Although, the field has seen significant increase in production rates in recent times, gas lift requirement has increased with increase in production and water cut. To maximize production and value from OML Z, it is expedient to seek an alternative artificial lift method that can debottleneck and unlock the potential of fields within OML Z where production has been less than 50% since the field was brought on stream. Production from the gas lifted fields within OML Z is constrained by a combination of bottlenecked gas lift facility and surface production facility. This study explores the different artificial lift methods and selects an applicable technology for OML Z using a developed selection criterion. Electrical Submersible Pump (ESP) found suitable for OML Z is further analyzed for feasibility and application within OML Z given existing limitations. The candidate reservoir and well selection criteria are elaborated upon, taking into consideration several elements that contribute to the production process. The results of the well and network models, that shows the significant gains attributed to the conversion of selected previously gas lifted wells to ESPs, are discussed. The economic benefit of such conversion is also shown.

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