The Evaluation Of Indirect Water Cut Measurement Using Coriolis Flowmeter Case Study : Kerisi Oil Allocation Meter

Abstract PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells. The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data. The three TTESP's installed in Field – T were of size 2.72" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window. The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.

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Innovations of Gas Lift in Prolific, Long-perforations, and Multilayered Wells, Case Study in Sudan

10.2118/afrc-2566102-ms ◽

2016 ◽

Author(s):

Xueqing Tang ◽

Lirong Dou ◽

Ruifeng Wang ◽

Jie Wang ◽

Shengbao Wang ◽

...

Keyword(s):

High Water ◽

Water Breakthrough ◽

Start Up ◽

Production Wells ◽

Decline Curves ◽

High Water Cut ◽

Water Cut ◽

Gas Lift

ABSTRACT Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects: Extend end of tubing to the bottom of perforations for commingled production of oil and condensate gas zones, in order to utilize condensate gas producing from the lower zones for in-situ gas lift.Produce well stream from the casing annulus while injecting natural gas into the tubing.High-pressure nitrogen generated in-situ was used to kick off the dead wells, instead of installation of gas lift valves for unloading. After unloading process, the gas from compressors was injected down the tubing and back up the casing annulus.For previous high water-cut producers, prior to continuous gas lift, approximately 3.6 MMcf of nitrogen can be injected and soaked a couple of days for anti-water-coning.Two additional 10-in. flow lines were constructed to minimize the back pressure of surface facilities on wellhead. As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.

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Case Study of Successful Matrix Stimulation of High-Water-Cut Wells in Dubai Offshore Fields

10.2523/iptc-13203-ms ◽

2009 ◽

Author(s):

Fathi Younis Shnaib ◽

Abdel Maksoud Mohamed Desouky ◽

Nagendra Mehrotra ◽

Mohamed Muhiz Kuthubdeen ◽

Gunther Rutzinger ◽

...

Keyword(s):

High Water ◽

High Water Cut ◽

Water Cut ◽

Stimulation Of

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Microbiologically influenced corrosion in floating production systems

Microbiology Australia ◽

10.1071/ma18050 ◽

2018 ◽

Vol 39 (3) ◽

pp. 165 ◽

Cited By ~ 1

Author(s):

Laura Machuca Suarez ◽

Anthony Polomka

Keyword(s):

Production Systems ◽

Microbiologically Influenced Corrosion ◽

Equipment Failure ◽

Chemical Treatments ◽

Corrosion Rates ◽

Increased Risk ◽

Offshore Oil Production ◽

Water Cut ◽

Offshore Oil

Microbiologically influenced corrosion (MIC) represents a serious and challenging problem in Floating, Production, Storage and Offloading vessels (FPSOs), one of the most common type of offshore oil production facilities in Australia. Microorganisms can attach to metal surfaces, which under certain conditions, can result in corrosion rates in excess of 10 mm per year (mmpy) leading to equipment failure before their expected lifetime. Particularly, increasing water cut (ratio of water vs. total fluids produced), normally resulting from the age of the assets, results in an increased risk of MIC. This paper provides an overview of causative microorganisms, their source of contamination and the areas within FPSOs that are most prone to MIC. Although mitigation practices such as chemical treatments, flushing and draining and even cathodic protection are effective, MIC can still occur if the systems are not properly monitored and managed. A case study is presented that describes the microorganisms identified in a FPSO operating in Australia suspected of having MIC issues.

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Two-Stage Geothermal Well Clustering for Oil-to-Water Conversion on Mature Oil Fields

Geosciences ◽

10.3390/geosciences11110470 ◽

2021 ◽

Vol 11 (11) ◽

pp. 470

Author(s):

Josipa Hranić ◽

Sara Raos ◽

Eric Leoutre ◽

Ivan Rajšl

Keyword(s):

Spatial Arrangement ◽

Oil Wells ◽

Oil Field ◽

Oil Fields ◽

Two Stage ◽

Oil Companies ◽

Geothermal Potential ◽

Clustering Approach ◽

Water Cut

There are numerous oil fields that are approaching the end of their lifetime and that have great geothermal potential considering temperature and water cut. On the other hand, the oil industry is facing challenges due to increasingly stringent environmental regulations. An example of this is the case of France where oil extraction will be forbidden starting from the year 2035. Therefore, some oil companies are considering switching from the oil business to investing in geothermal projects conducted on existing oil wells. The proposed methodology and developed conversions present the evaluation of existing geothermal potentials for each oil field in terms of water temperature and flow rate. An additional important aspect is also the spatial distribution of existing oil wells related to the specific oil field. This paper proposes a two-stage clustering approach for grouping similar wells in terms of their temperature properties. Once grouped on a temperature basis, these clusters should be clustered once more with respect to their spatial arrangement in order to optimize the location of production facilities. The outputs regarding production quantities and economic and environmental aspects will provide insight into the optimal scenario for oil-to-water conversion. The scenarios differ in terms of produced energy and technology used. A case study has been developed where the comparison of overall fields and clustered fields is shown, together with the formed scenarios that can further determine the possible conversion of petroleum assets to a geothermal assets.

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