Comprehensive Approach to Tackle Systemic Failure in Gas Lift Valves in Pre Salt Wells

2021 ◽  
Author(s):  
Elaine Daniele M P C Real ◽  
Thiago Geraldo Silva ◽  
Otavio Borges Ciribelli ◽  
Tatiana Sanomya
Keyword(s):  
Failure Process ◽  
Comprehensive Approach ◽  
Fluid Composition ◽  
Artificial Lift ◽  
Production Wells ◽  
Production History ◽  
Early Failures ◽  
Water Cut ◽  
The Impact ◽  
Gas Lift

Abstract This work describes a comprehensive approach to tackle systemic failure in gas lift valves in pre-salt wells. Failure analyses in gas lift valves were performed after unexpected early failures leading to tubing-annulus communication. Understanding the root causes of this problem generates value for assets, increasing equipment life, preventing unnecessary workover, and reducing costs. Suspect failed valves are systematically removed from the wells, usually by slick-line workovers, and brought to an onshore workshop, where their integrity and mechanical functionality can be analyzed. The valve's run life, equipment model and manufacturer, annular fluid, flow through the gas lift valve, operational pressure and temperature, composition of reservoir fluids and solids deposition were verified. Besides, transient simulations were carried out to provide insights on the root causes of the failure. Also, a good understanding on how each valve works, including its engineering design, was necessary to thoroughly understand the failure process. The study of gas-lift injection valves early failure in pre-salt wells have been an excellent way to understand the life cycle of production wells before the need to start lift gas injection. That leads to a comprehensive understanding about the effects of the fluids left in annulus and have supported Petrobras in most effectively managing of well integrity and workover costs. The analysis incorporates the impact of oil production, water cut, completion type, annular fluid composition, anti-scaling fluid injection (composition and efficiency) and the differential pressure between the tubing of the annulus in the valve failure model. The composition of the deposit found inside the valves and the production history of the well were essential to assemble the puzzle of how the failure mechanism works. With the acquired knowledge, it has been possible to apply barriers to avoid future events of unwanted tubing-annulus communication arising from gas-lift valve failures. This article provides a methodology and examples for a most effective understanding of the gas-lift valves failure mechanisms and their root causes, which proved to be a valuable tool for the artificial lift design and for the planning of well operations. That has contributed to maximize equipment life, cost reduction and, at last, generating value for the company.

Stabilisation of Gaslift Production Using a Dynamic Simulator

2001 ◽  
Author(s):  
Yvonne V. Roberts ◽  
Matt Nicol
Keyword(s):  
Production Management ◽  
Mechanical Damage ◽  
Phase Changes ◽  
Fluid Composition ◽  
Remedial Action ◽  
Original Design ◽  
The North ◽  
Water Cut ◽  
The Impact ◽  
Gas Lift

Abstract A common problem with gas lifted wells is the development, over time, of instabilities in the injection/production behaviour. The question raised is initially that of “probable cause and effect”; the understanding of which is essential to the determination of possible remedial action. The major causes of unstable behaviour fall into three broad categories: • Design related - the original design is inappropriate or inflexible. • Mechanical - damage to, and/or failure of, valves and equipment. • Dynamic flow behaviour - changes in fluid composition and/or phase changes. Commonly, the instability incorporates elements from more than one category. This paper discusses one case in which a horizontal well in the North Sea, which had a gas lift completion designed for operation at a water cut of around 20%, exhibited unstable production after a rapid rise in water cut to approximately 80%. The paper shows how a new and unique dynamic gas lift simulator was used to reproduce the observed well behaviour, and how the model was then used to recommend remedial action to stabilise production. The impact of these remedial actions is discussed in the context of the overall production management. Finally, the implementation of the recommendations and the subsequent well behaviour are presented.

scholarly journals Gas Injection Optimization to Increase Oil Production at MRA PT. PHE ONWJ

2021 ◽  
Vol 2 (2) ◽  
pp. 75
Author(s):  
Harry Budiharjo Sulistyarso ◽  
KRT Nur Suhascaryo ◽  
Mochamad Jalal Abdul Goni
Keyword(s):  
Gas Injection ◽  
Economic Feasibility ◽  
Feasibility Analysis ◽  
Offshore Platforms ◽  
Total Production ◽  
The North ◽  
Artificial Lift ◽  
Production Wells ◽  
Java Sea ◽  
Gas Lift

The MRA platform is one of the offshore platforms located in the north of the Java Sea. The MRA platform has 4 production wells, namely MRA-2ST, MRA-4ST, MRA-5, and MRA-6 wells. The 4 production wells are produced using an artificial lift in the form of a gas lift. The limited gas lift at the MRA Platform at 3.1 MMSCFD makes the production of wells at the MRA Platform not optimal because the wells in the MRA Platform are experiencing insufficient gas lift. Optimization of gas lift injection is obtained by redistribution of gas lift injection for each. The results of the analysis in this study indicate that the optimum gas lift injection for the MRA-2ST well is 0.5552 MMSCFD, the MRA-6 well is 1.0445 MMSCFD, the MRA-5 well is 0.7657 MMSCFD, finally the MRA-4ST well with gas injection. lift is 0.7346 MMSCFD. The manual gas lift in the MRA-4ST is also replaced based on an economic feasibility analysis to ensure that the gas lift injection for each well can be kept constant. The redistribution of gas lift carried out by the author has increased the total production rate of the MRA Platform by 11,160 BO/year or approximately USD 781,200/year. Keywords: Gas lift; Insufficient; Optimization

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

2021 ◽  
Vol 73 (03) ◽  
pp. 46-47
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Primary System ◽  
Artificial Lift ◽  
Short Period ◽  
Production History ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Available Information ◽  
Offshore Oil

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

Cable Thru Downhole Insert Safety Valve: A New Paradigm

2021 ◽  
Author(s):  
Kuswanto Kuswanto ◽  
Oka Fabian ◽  
Orient B Samuel ◽  
Mohd Yuzmanizeil B Yaakub ◽  
Chua Hing Leong ◽  
...  
Keyword(s):  
Safety Valve ◽  
Cost Effective ◽  
Submersible Pump ◽  
New Paradigm ◽  
Reservoir Properties ◽  
Technology Application ◽  
Artificial Lift ◽  
Water Cut ◽  
The Right ◽  
Gas Lift

Abstract The B Field is located in the South China Sea, about 45 KM offshore Sarawak, Malaysia, in a water depth approximately 230 ft. Its structure is generally regarded as a gentle rollover anticline with collapsed crest resulting from growth faulting. The reservoirs were deposited in a coastal to shallow marine with some channels observed. Multiple stacked reservoirs consist of a series of very thick stacked alternating sandstone and minor shale layers with differing reservoir properties. The shallow zones are unconsolidated, and the wells were completed with internal gravel packs. Wells in B Field mostly were completed in multi-layered reservoirs as dual strings with SSDs and meant to produce as a commingled production. The well BX is located within B Field and designed as oil producer well with a conventional tubing jointedElectrical Submersible Pump (ESP) system which was installed back in 2008. Refer to figure 1, the initial completion schematic is 3-1/2″ single string that consist of the single production packer, gas lift mandrel, tubing retrievable Surface Controlled Subsurface Safety Valve (SCSSV) and ESP. The production packers equipped with the feed thru design to accommodate the ESP cable and the gas vent valve as part of the ESP completion design. The gas lift mandrel was installed in the completion string as a backup artificial lift method to receive the gas lift and orifice valve in the event of the conventional ESP failed. Hence the well still able to produce by introducing the gas thru the annulus to activate the gas lift valve. Eventually throughout the end of the the field life, the well would depend on the ESP system for the primary lifting method due to gas lift depth limitation and the gas supply. The conventional ESP failed after seven years of operation which is above the average ESP lifetime. The well last produced at a flow rate with 28 % water cut, however the well is not at the end of the field life. Based on the economical study with the right technology and cost efficient approach, the well still economicaly profitable. The Thru Tubing (TT) ESP technology is approached as cost effective solution compare to fully well workover. Despite a couple of operational challenges, for example, setting the cable hanger, maintaining downhole barrier requirement, the Thru Tubing Electrical Submersible Pump Cable Deployed (TTESP CD) and Cable Thru Insert Safety Valve (CT-ISV) was successfully installed. Several post-installation findings have uncovered some problems which are requiring some additional technical and operation improvement for future similar applications. This paper will highlight the deployment of the Cable Thru Insert Safety Valve (CT-ISV) that was successfully installed as pilot, which is the first application in the world, and also highlights the success, lesson learnt and improvement for future requirement for the CT-ISV application as one of the solution for retrofitting completion application without jeopardizing the well integrity. This achievement is collaboration between Company and service partner as the technology and deployment under the proprietary scope. Further technology application, the replication of this insert safety valve was conducted and successfully deployed on other three wells.

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.

Development and Implementation of the Technology of a Mobile Gas-Lift Complex For Transferring Wells of the Block-Conductor of the Field Named After Yu. Korchagin For Artificial Lift

2021 ◽  
Author(s):  
Alexsandr Zavyalov ◽  
Ivan Yazykov ◽  
Marat Nukhaev ◽  
Konstantin Rymarenko ◽  
Sergey Grishenko ◽  
...  
Keyword(s):  
Technology Implementation ◽  
Liquid Mixture ◽  
Economic Feasibility ◽  
Flow Metering ◽  
Artificial Lift ◽  
Production Wells ◽  
Study Implementation ◽  
And Control ◽  
Gas Lift ◽  
Gas Supply

Abstract This paper is aimed at the mobile gas-lift unit installation workup to shift the wells of the conductor platform of the Yu. Korchagin field to mechanized extraction instead of constructing a gas lift pipeline. The paper presents all the stages of this technology implementation, from conceptual design, engineering calculations, to the economic feasibility study, implementation and operation of this unit. During the operation of the wells of the conductor platform at the Yu. Korchagin field, the following problem occurred: a gas-lift gas pipeline was not constructed from the offshore ice-resistant fixed platform to the conductor platform, as they wanted to shift the wells to the mechanized extraction method (artificial lift). An alternative option to provide gas-lift gas to the wells of the conductor platform is to install a mobile gas-lift unit directly on an unmanned platform. This mobile gas-lift unit will be a compact separator of a gas-liquid mixture from a donor well, and it will pipe a separated gas-lift gas supply system with control and flow metering sets into the production wells. This system enables a shift of the wells of an unmanned conductor platform to a compressor-less gas-lift operation and a remote regulation of production and control over the wells operation.

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Wenting Yue ◽  
John Yilin Wang
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Improved Oil Recovery ◽  
Smackover Formation ◽  
Artificial Lift ◽  
Production History ◽  
Current Production ◽  
The Impact

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

scholarly journals GAS LIFT OPTIMIZATION OF A MATURE WELL IN NIGER DELTA, NIGERIA USING INCOMPLETE DATASET: A CASE STUDY

2020 ◽  
Vol 4 (1) ◽  
pp. 15-18
Author(s):  
Oghenegare E. Eyankware ◽  
Idaereesoari Harriet Ateke ◽  
Okonta Nnamdi Joseph
Keyword(s):  
Niger Delta ◽  
Gas Injection ◽  
Injection Rate ◽  
Wellhead Pressure ◽  
Well Production ◽  
Artificial Lift ◽  
Lift Mechanism ◽  
Fluid Production ◽  
Water Cut ◽  
Gas Lift

Well DEF, a well located in Niger Delta region of Nigeria was shut down for 7 years. On gearing towards re-starting production, different options such as installation of gas lift mechanism, servicing and installation of packers and valves were evaluated for possibility of increasing well fluid productivity. Hence, this research was focused on optimizing well fluid productivity using PROSPER through installation of continuous gas lift mechanism on an existing well using incomplete dataset; in addition, the work evaluated effect of gas injection rates, wellhead pressure, water cut and gas gravity on efficiency of the artificial lift mechanism for improved well fluid production. Results of the study showed that optimum gas injection rate of 0.6122 MMscf/day produced well fluid production of 264.28 STB/day which is lower than pristine production rate (266 STB/day) of the well. Also, increment in wellhead pressure resulted in decrease in well production, increase in water cut facilitated reduction in well fluid productivity while gas gravity is inversely proportional to well fluid productivity. Based on results obtained, authors concluded that Well DEF does not require gaslift mechanism hence, valves and parkers need to be re-serviced and re-installed for sustained well fluid.

Improvements in understanding short-range permeability variability in coal seam gas reservoirs

2016 ◽  
Vol 56 (2) ◽  
pp. 555
Author(s):  
Stephen Tyson ◽  
Suzanne Hurter ◽  
Fengde Zhou ◽  
Morteza Jami
Keyword(s):  
Short Range ◽  
Simulation Models ◽  
Holistic Approach ◽  
Predictive Modelling ◽  
Gas Production ◽  
Production Performance ◽  
Improve Measurement ◽  
Production Wells ◽  
Production History ◽  
The Impact

After several years of production history on at least some of the more than 7,000 CSG production wells in the Surat and Bowen basins, reservoir engineers continue to note that understanding detailed permeability spatial variation near the well bore and its impact on actual production performance remains poor. There is a growing realisation that permeability of coals has an even higher variability than was initially expected, and that this variability occurs across a shorter range than that of the typical inter-well spacing (~750 m). As a result, flow between wells, pressure depletion, water and gas production rates and ultimate recovery is difficult to predict. Forecasting short-range continuity of different categories of absolute permeabilities through modelling is the key challenge. Other physical or geophysical parameters may change similarly with the same range. Generation models tend to over-estimate the lateral continuity of coals and associated carbonaceous shales resulting in a poor match between the model predictions and the observed production data. This may be due to incomplete information on the short-range variability of porosity and permeability and the appropriate up-scaled values for these parameters used in the reservoir simulation models. This extended abstract discusses controls on permeability, both the geological influences and the impact of drilling and completion on permeability. Taking a holistic approach to the problem of understanding permeability variability, the relative impact of these controls is estimated and discussed. With the benefit of rudimentary ranking of these controls, techniques have been developed to improve measurement and modelling of permeability variability. These approaches can help improve the predictive modelling capability of reservoir performance.

scholarly journals Production Data Analysis and Sonolog for Determining Artificial Lift Design and Well Characteristic

2020 ◽  
Vol 1 (1) ◽  
pp. 28
Author(s):  
Bambang Bintarto ◽  
Rizky Rahmat Auliya ◽  
Riza Andhika Mahendra Putra ◽  
Afif Surya Pradipta ◽  
Rafli Arie Kurnia
Keyword(s):  
Produced Water ◽  
Submersible Pump ◽  
Water Control ◽  
Injection Wells ◽  
Diagnostic Plot ◽  
Artificial Lift ◽  
Production Wells ◽  
Production History ◽  
Electric Submersible Pump

Tarakan Field, North Kalimantan is a part of PT. Pertamina EP Asset 5. The Tarakan Field has 5 structures in the form of Pamusian, Juata, Sesanip, Mangatal, and Sembakung. The Tarakan Field has 57 production wells and 6 injection wells. The wells at Tarakan field are produced with artificial lifts in the form of Sucker Rod Pump (SRP) totaling 25, Hydraulic Pumping Unit (HPU) totaling 11, Electric Submersible Pump (ESP) totaling 19 and Progressive Cavity Pump (PCP) totaling 2. The determination of artificial lifts is carried out by the design of well characteristics and production history. The design at Tarakan Field was carried out with an artificial lift in the form of ESP (Electric Submersible Pump). ESP is used according to reservoir and formation characteristics in Tarakan Field. Water Control Diagnostic Plot is a method used to analyze the effect of control on produced water. Water Control Diagnostic plot is plot between WOR and WOR derivative vs time. The plot was carried out on a log-log scale. The plot on the Water Control Diagnostic Plot is then analyzed against the graph created by the KS Chan. So from the analyzed plot, it is found whether or not there is a problem in the well at Tarakan Field. The results of the graph analysis on the well at Tarakan Field on the chart show that the field does not indicate a problem. Keywords: chan plot; design; esp; production

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