Case Study-Investigating Probable Root Causes Behind Consistent Higher Water Cut in a Mother CBM Well than its Deviated Wells: Well Spacing, Well Stimulation, and Overlying Strata Viewpoints and Recommendations

2014 ◽  
Author(s):  
Sreerama Chandra ◽  
Faraaz Adil
Keyword(s):  
Well Stimulation ◽  
Well Spacing ◽  
Water Cut ◽  
Overlying Strata ◽  
Deviated Wells

Troubleshooting Cable Deployed Thru Tubing Electrical Submersible Pumps: A Case Study from South East Asia

2021 ◽  
Author(s):  
Saurabh Anand ◽  
Eadie Azahar B Rosland ◽  
Elsayed Ouda Ghonim ◽  
Latief Riyanto ◽  
Khairul Azhar B Abu Bakar ◽  
...  
Keyword(s):  
Low Cost ◽  
Power Cable ◽  
Related Data ◽  
Root Cause ◽  
Artificial Lift ◽  
Electrical Submersible Pumps ◽  
Cause Of Failure ◽  
Water Cut ◽  
Discharge Pressure

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.

Review of Practical Experience by Polymer Flooding at Daqing

2009 ◽  
Vol 12 (03) ◽  
pp. 470-476 ◽  
Author(s):  
Dongmei Wang ◽  
Huanzhong Dong ◽  
Changsen Lv ◽  
Xiaofei Fu ◽  
Jun Nie
Keyword(s):  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Molecular Weights ◽  
Well Spacing ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following:Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity, involving the optimum combination of oil strata during flooding and well-pattern design, respectively;Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs;The entire polymer-flooding process should be characterized in five stages--with its dynamic behavior distinguished by water-cut changes; -Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; andContinuous innovation must be a priority during polymer flooding. Introduction China's Daqing oil field entered its ultrahigh-water-cut period after 30 years of exploitation. Just before large-scale polymer-flooding application, the average water-cut was more than 90%. The Daqing oil-field is a large river-delta/lacustrine facies, multilayered with complex geologic conditions and heterogeneous sandstone in an inland basin. After 30 years of waterflooding, many channels and high-permeability streaks were identified in this oil field (Wang and Qian 2002). Laboratory research began in the 1960s, investigating the potential of enhanced-oil-recovery (EOR) processes in the Daqing oil field. After a single-injector polymer flood with a small well spacing of 75 m in 1972, polymer flooding was set on pilot test. During the late 1980s, a pilot project in central Daqing was expanded to a multiwell pattern with larger well spacing. Favorable results from these tests--along with extensive research and engineering from the mid-1980s through the 1990s--confirmed that polymer flooding was the preferred method to improve areal- and vertical-sweep efficiency at Daqing and to provide mobility control (Wang et al. 2002, Wang and Liu 2004). Consequently, the world's largest polymer flood was implemented at Daqing, beginning in 1996. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding boosted the ultimate recovery for the field to more than 50% of original oil in place (OOIP)--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 10 million tons (73 million bbl) per year (sustained for 6 years). The focus of this paper is on polymer flooding, in which sweep efficiency is improved by reducing the water/oil mobility ratio in the reservoir. This paper is not concerned with the use of chemical gel treatments, which attempt to block water flow through fractures and high-permeability strata. Applications of chemical gel treatments in China have been covered elsewhere (Liu et al. 2006).

Determining Optimal Well Spacing in the Marcellus Shale: A Case Study Using an Integrated Workflow

2018 ◽  
Author(s):  
Piyush Pankaj ◽  
Priyavrat Shukla ◽  
Payam Kavousi ◽  
Timothy Carr
Keyword(s):  
Marcellus Shale ◽  
Well Spacing

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

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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