A Dynamic Simulation Assessment for Relocating Flare System into Separated Platform Utilizing Idle Subsea Main Oil line

Abstract KLB is an offshore platform that consists of production wells and two train gas lift compressors. During well intervention, the KLB operation team must turn off the flaring system due to potential flare radiation of more than 500 BTU/hr-ft2at the working area and gas dispersion more than 50 %-LEL at the flare tip. The relocation of the KLB flaring system to the nearest platform keeps the KLB gas lift compressor operating during this activity. The relocation scenario can maintain the KLB platform production of 700 BOPD. KLA Flowstation is the nearest platform to the KLB. It is separated one kilometer, connected by an idle subsea oil pipeline, but there are no pigging facilities due to limited space at the KLB platform. Therefore, the comprehensive assessment to relocate the KLB flaring system is a) Flare system study using Flare Network software to simulate backpressure and Mach Number at tailpipe in the KLA and KLB flaring system; b). Dynamic transient simulation using Flow Assurance Software to calculate backpressure, liquid hold up, and slugging condition in the flare KO drum; and c). Flare radiation and dispersion study. The initial condition of the idle subsea oil pipeline was full of liquid as the preservation for a pipeline to prevent a further oil spill in case of a leak during the idle condition. The dewatering process for the idle subsea pipeline has been conducted by purging the pipeline utilizes 0.7 MMscfd gas lift with a pressure of 100 psig to displace liquid content to 20 bbl. The transient simulation for gas swapping was conducted at a gas rate of 4.1 MMscfd as the train compressor's flaring condition. The calculated backpressure at the KLB safety valve is 12.3 psig below the required maximum of 30 psig. The calculated liquid surge volume in the Flare KO drum during flaring is 17 bbl and can be handled by surge volume inside the KO drum. The predicted condensation inside the subsea pipeline shows that the maximum operation of the flaring system is limited to 30 days. The radiation and gas dispersion to the nearest facility is within a safe limit. The KLB teams successfully conducted the relocation of the flaring system from the KLB platform to the KLA platform. The result was no interruption of production, no risk of radiation, and no potential explosion during a well intervention. Experience in the last two activities has confirmed that this method can prevent revenue loss of 19 billion rupiahs. This study has initiated a new engineering standard and best practice for flaring systems as opposed to the current practice which states that the flare location shall be at the same location as the production facilities with no pocket piping in between. This study and field experience have proved that the flaring system can be located on a different platform by conducting engineering assessments to ensure process and process safety criteria are within Company and International Standard.

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

Journal of Petroleum and Geothermal Technology ◽

10.31315/jpgt.v2i2.5519 ◽

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

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Pre-Production Deployed Scale Inhibition Treatments in Deep-Water, West Africa

10.2118/spe-169784-ms ◽

2014 ◽

Author(s):

D.. Patterson ◽

W.. Williams ◽

M.. Jordan ◽

R.. Douglas

Keyword(s):

West Africa ◽

Deep Water ◽

Best Practice ◽

Barium Sulphate ◽

Scale Inhibitor ◽

Monitoring Methods ◽

Initial Water ◽

Scale Inhibition ◽

Production Wells ◽

Scale Control

Abstract The injection of seawater into oil-bearing reservoirs in order to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deep-water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulphate scaling tendency upon breakthrough of injection seawater meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts have proven to be at sufficient risk to require early squeeze application. To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid perforation wash and overflush stages prior to frac packing operations. The deployment of this inhibitor proved effective in controlling barium sulphate scale formation during initial water production eliminating the need to scale squeeze the wells at low water cuts (<10% BS&W). To increase the volumes of scale inhibitor being deployed in the pre-production treatments and so extend the treatment lifetimes scale inhibitor was also added to the frac gel used to carry the frac sand. This paper outlines the selection methods for the inhibitor chemical for application in frac fluids in terms of rheology, retention/release, formation damage and presents the chemical returns profile from the 5 wells treated (some treatments lasting > 300 days) along with monitoring methods utilized to confirm scale control in the wells treated. Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.

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Oil spill risk assessment for a Single Buoy Mooring terminal in the Port of Taranto (Southern Italy)

10.5194/egusphere-egu21-4662 ◽

2021 ◽

Author(s):

Svitlana Liubartseva ◽

Ivan Federico ◽

Giovanni Coppini ◽

Rita Lecci

Keyword(s):

Risk Assessment ◽

Oil Spill ◽

Oil Spills ◽

Cost Benefit Analysis ◽

Cost Benefit ◽

Oil Refinery ◽

Plant Oil ◽

Contamination Assessment ◽

Subsea Pipeline ◽

Oil Pipeline

Being situated in a semi-enclosed Mediterranean lagoon, the Port of Taranto represents a transport, industrial and commercial hub, where the port infrastructure, a notorious steel plant, oil refinery and naval shipyards coexist with highly-dense urban zone, recreation facilities, mussel farms, and vulnerable environmental sites. A Single Buoy Mooring in the center of the Mar Grande used by tankers and subsea pipeline that takes oil directly from tanker to refinery are assumed to stay at risk of accidental oil spills, despite significant progress in technology and prevention.The oil spill model MEDSLIK-II (http://medslik-ii.org) coupled to the high resolution Southern Adriatic Northern Ionian coastal Forecasting System (SANIFS http://sanifs.cmcc.it Federico et al., 2017) is used to model hypothetical oil spill scenarios in stochastic mode. 15,000+ hypothetical individual spills are generated from randomly selected start locations: 50% from a buoy and 50% along the subsea pipeline 2018&#8211;2020. Individual spill scenario is based on a real crude oil spill caused by a catastrophic pipeline failure happened in Genoa in April 2016 (Vairo et al., 2017). The model outputs are processed statistically to represent quantitively: (1) timing of the oil drift; (2) hazard maps in probability terms at the sea surface and on the coastline; (3) oil mass balance; (4) local-zone contamination assessment.The simulations reveal that around 48% of the spilled oil will evaporate during the first 8 hours after the accident. Being transported by highly variable currents and waves, the rest is additionally exposed to multiply reflections from sea walls and concrete wharfs that dominate in the study area. As a result, the oil will be dispersed almost isotropically in the Mar Grande, indicating a rather moderate or small level of concentrations over the minimum threshold values (French McCay, 2016).We have concluded that at a probability of 50%, the first oil beaching event will happen within 14 hours after the accident. The most contaminated areas are predicted on and around the nearest Port berths, on the coastlines of the urban area and on the tips of the breakwaters that frame the Mar Grande openings. The remote areas of the West Port and Mar Piccolo are expected to be the least contaminated ones.Results are applicable to contingency planning, ecological risk assessment, cost-benefit analysis, and education.This work is conducted in the framework of the IMPRESSIVE project (#821922) co-funded by the European Commission under the H2020 Programme.ReferencesFederico, I., Pinardi, N., Coppini, G., Oddo, P., Lecci, R., Mossa, M., 2017. Coastal ocean forecasting with an unstructured grid model in the southern Adriatic and northern Ionian seas. Nat. Hazards Earth Syst. Sci., 17, 45&#8211;59, doi: 10.5194/nhess-17-45-2017.French McCay, D., 2016. Potential effects thresholds for oil spill risk assessments. Proc. of the 39 AMOP Tech. Sem., Environment and Climate Change Canada, Ottawa, ON, 285&#8211;303.Vairo, T., Magr&#236;, S., Qualgliati, M., Reverberi, A.P., Fabiano, B., 2017. An oil pipeline catastrophic failure: accident scenario modelling and emergency response development. Chem. Eng. Trans., 57, 373&#8211;378, doi: 10.3303/CET1757063.

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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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Process safety common lead metrics: implementing and learning

The APPEA Journal ◽

10.1071/aj15050 ◽

2016 ◽

Vol 56 (2) ◽

pp. 544

Author(s):

Steve Fogarty

Keyword(s):

Best Practice ◽

Management Systems ◽

Process Safety ◽

Chemical Safety ◽

Common Lead ◽

Tier System ◽

The Us ◽

The Common ◽

Safety Metrics ◽

Selection Of

No matter which major accident event investigation is looked into, some common themes concerning the requirements for process safety metrics present themselves. For example, the recent Macondo investigation by the US Chemical Safety Board (CSB) examined both API 754 and IOGP 456, and re-iterated that metrics need to be developed to capture the health of barriers and management systems. The effectiveness of barriers and management systems needs to be assessed, as does the frequency that these barriers are being called upon to make sure that the risk is being properly managed. Both API 754 and IOGP 456 use the four-tier system, where the top two tiers are lagging, and tiers three and four are more leading. Both standards focus on reporting and benchmarking the lagging metrics; however, the selection of leading metrics is left to be determined by individual companies. Recent work completed by the IChemE Safety Centre (ISC) focuses on these leading metrics, but takes a different approach by developing a suite of 21 common lead metrics that allows for developments to occur. By having common metrics across companies and across industries, ISC and its member companies are at the groundbreaking point where benchmarking and identification of best practice can begin. APPEA is leading the charge with a unanimous agreement by the CEOs at the April CEO meeting to implement the common lead metrics across the APPEA companies. Quadrant Energy is well underway with its journey, and this extended abstract discusses the process being undertaken to commence reporting on all 21 of these process safety common lead metrics.

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Material Selection for Subsea Pipeline Construction under Uncertainties for Niger Delta Region

Journal of Engineering Research and Reports ◽

10.9734/jerr/2020/v14i317128 ◽

2020 ◽

pp. 34-43

Author(s):

N. E. Udosoh ◽

Clement Idiapho ◽

Sani Awwal

Keyword(s):

Niger Delta ◽

Material Selection ◽

Research Work ◽

Delta Region ◽

Pipeline Construction ◽

Subsea Pipeline ◽

Oil Pipeline ◽

Niger Delta Region ◽

Selection For ◽

Operational Error

This research work on material selection for subsea pipeline construction was carried out to analyze and recommend suitable material option that satisfies DNV-OS-F101 standard for subsea pipeline constructions which will not succumb to extreme conditions and performs well in unpredictable conditions in the Niger Delta Region of Nigeria. Crude oil is mainly transported through pipelines, structural failure of the pipelines will severely affect oil production processes and will cause huge economic loss. Data on oil pipeline failures in the Niger Delta region of Nigeria were gathered and the major causes were; corrosion, operational error, third party activities and mechanical failures which were associated with the construction materials and structures of the pipelines. Hence, material selection for subsea pipelines is of vital importance. This paper makes use of Technique for Order Preference by Similarity to the Ideal Solution (TOPSIS) Theory to make fuzzy evaluation of different material options for pipeline construction. Statistical data and experts’ knowledge were integrated in addressing data limitation. This paper utilizes related weights and normalized scores based on experts’ judgements and with the aid of value engineering (VE) method, material criteria based on DNV-OS-F101 standard and TOPSIS Theory to achieve the best material option. The analysis has demonstrated that the estimation of TOPSIS is reliable. The outcome obtained can be used to assist the decision maker in the selection of the best material option suitable for the construction of subsea pipeline in Niger Delta region.

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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

10.2118/206471-ms ◽

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.

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