Water Injection Operation Readiness of BB Field Redevelopment

2021 ◽  
Author(s):  
Sriyanta Hadi ◽  
M Junaida Hoodi ◽  
Sing Tat Ting ◽  
Setia Dana ◽  
Sabestiano Mike Atet
Keyword(s):  
Best Practices ◽  
Oil Recovery ◽  
Produced Water ◽  
New Technology ◽  
Water Injection ◽  
Working Environment ◽  
Central Processing ◽  
Infill Drilling ◽  
Integrated Project ◽  
B1 Field

Abstract BB field complex redevelopment is an integrated development under PETRONAS Enhanced Oil Recovery (EOR) project. BB fields are producing fields operated by PETRONAS Carigali Sendirian Berhad (PCSB). The BB fields redevelopment is a project to redevelop both B1 and B2 fields and to enable EOR implementation in the B1 field. The B1 redevelopment includes the EOR implementation through immiscible water alternating gas (IWAG), infill drilling, and safeguarding of no further activity (NFA) production. The B1 redevelopment also incorporates some provisions for the B2 field to secure gas supply for B1 IWAG. The B2 redevelopment focuses on safeguarding B2 NFA production. The redevelopment consists of three main elements, 1) EOR IWAG that involves injector well drilling at a new IWAG injection wellhead platform, 2) infill drilling at existing platforms and 3) safeguarding of NFA. Surface facilities scope includes installing a new Central Processing Platform (CPP) for B1 field, wellhead platforms, and intra-field pipelines. The CPP includes 60 kbpd water injection plant capacity, gas compression, gas-liquid separation, and produced water treatment. Modification in the B2 field is to flow gas from the B2 field to the B1 field. Operational readiness is crucial to ensure that the integrated project is executed smoothly. Two cases for changes are new technology deployment for water injection module (WIM) and people capability. It is a big challenge to achieve an effective start-up with minimum delay. There are some important aspects considered includes operation philosophy, Health Safety and Environment (HSE), and collaborative working environment (CWE) implementation. It is important to ensure improving oil recovery through infill and IWAG. Best practices in operation readiness of an integrated project that have many challenges that include process, people, and technology. These best practices may be replicated in any other projects by other companies/operators.

Produced Water Management Strategy and Water Injection Best Practices: Design, Performance, and Monitoring

2007 ◽  
Vol 22 (01) ◽  
pp. 59-68 ◽  
Author(s):  
Ahmed S. Abou-Sayed ◽  
Karim S. Zaki ◽  
Gary Wang ◽  
Manoj Dnyandeo Sarfare ◽  
Martin H. Harris
Keyword(s):  
Water Management ◽  
Best Practices ◽  
Management Strategy ◽  
Produced Water ◽  
Water Injection ◽  
Design Performance ◽  
Water Management Strategy

An Experimental Research on Enhanced Oil Recovery Using Local Polymers

2021 ◽  
Author(s):  
Abiola Oyatobo ◽  
Amalachukwu Muoghalu ◽  
Chinaza Ikeokwu ◽  
Wilson Ekpotu
Keyword(s):  
Enhanced Oil Recovery ◽  
Experimental Research ◽  
Oil Recovery ◽  
Capital Investment ◽  
Oil And Gas ◽  
Produced Water ◽  
Water Injection ◽  
Gum Arabic ◽  
Oil And Gas Industry ◽  
Profile Control

Abstract Ineffective methods of increasing oil recovery have been one of the challenges, whose solutions are constantly sought after in the oil and gas industry as the number of under-produced reservoirs increases daily. Water injection is the most extended technology to increase oil recovery, although excessive water production can pose huge damage ranging from the loss of the well to an increase in cost and capital investment requirement of surface facilities to handle the produced water. To mitigate these challenges and encourage the utilization of local contents, locally produced polymers were used in polymer flooding as an Enhanced Oil Recovery approach to increase the viscosity of the injected fluids for better profile control and reduce cost when compared with foreign polymers as floppan. Hence this experimental research was geared towards increasing the efficiency of oil displacement in sandstone reservoirs using locally sourced polymers in Nigeria and also compared the various polymers for optimum efficiency. Starch, Ewedu, and Gum Arabic were used in flooding an already obtained core samples and comparative analysis of this shows that starch yielded the highest recovery due to higher viscosity value as compared to Ewedu with the lowest mobility ratio to Gum Arabic. Finally, the concentration of Starch or Gum Arabic should be increased for optimum recovery.

An Experimental Study on Adaptability of a Novel Living Polymer Used in Low Permeability Fractured Reservoir

2013 ◽  
Vol 631-632 ◽  
pp. 140-144
Author(s):  
Li Li
Keyword(s):  
Oil Recovery ◽  
Volume Expansion ◽  
Concentration Ratio ◽  
Produced Water ◽  
Water Injection ◽  
Low Permeability ◽  
Fractured Reservoir ◽  
Injection Volume ◽  
Swelling Rate ◽  
Injection Property

In this paper, the produced water in Daqing oilfield was detected, includes the viscosity and concentration ratio of living polymer (LH-1), interfacial tension and swelling rate of particle polymer (LHP-1). And its adaptability in low permeable fracture core was also tested. The results show that the injection property is good if the living polymer (LH-1) and the particle polymer (LHP-1) are used together, the volume-expansion particle polymer can effectively plugging the high permeable layer in bottom of the reservoir and improve water injection profile. The best injection volume of LH-1is 0.32 PV, and enhances oil recovery rate is 18.4%.

Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Reservoir Simulation ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Water Flooding ◽  
Water Salinity ◽  
History Match ◽  
Infill Drilling ◽  
Salinity Data

Abstract This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production. A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves. The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented. Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.

Water Injection, Polymer Injection and Polymer Alternating Water Injection for Enhanced Oil Recovery: A Laboratory Study

2013 ◽  
Author(s):  
Marcelo F. Zampieri ◽  
Rosangela B. Z. L. Moreno
Keyword(s):  
Oil Recovery ◽  
Produced Water ◽  
Water Injection ◽  
Mobility Ratio ◽  
Sweep Efficiency ◽  
Polymer Injection ◽  
Paraffin Oil ◽  
Water Viscosity ◽  
Water Volumes ◽  
Expensive Process

Developing an efficient methodology for oil recovery is extremely important in this commodity industry, which may indeed lead to wide spread profitability. In the conventional water injection method, oil displacement occurs by mechanical behavior between fluids. Nevertheless, depending on mobility ratio, a huge quantity of injected water is necessary. Polymer injection aims to increase water viscosity and improve the water/oil mobility ratio, thus improving sweep efficiency. The alternating banks of polymer and water injection appear as an option for the suitable fields. By doing so, the bank serves as an economic alternative, as injecting polymer solution is an expensive process. The main objective of this study is to analyze and comparison of the efficiency of water injection, polymer injection and polymer alternate water injection. For this purpose, tests were carried out offset in core samples of sandstones using paraffin oil, saline solution and polymer and were obtained the recovery factor and water-oil ratio for each method. The obtained results for the continuous polymer injection and alternating polymer and water injection were promising in relation to the conventional water injection, aiming to anticipate the oil production and to improve the water management with the reduction of injected and produced water volumes.

scholarly journals Chemical enhanced oil recovery and the dilemma of more and cleaner energy

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Rouhi Farajzadeh ◽  
Siavash Kahrobaei ◽  
Ali Akbari Eftekhari ◽  
Rifaat A. Mjeni ◽  
Diederik Boersma ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Energy Demand ◽  
Produced Water ◽  
Transition Period ◽  
Water Injection ◽  
Energy Transition ◽  
Polymer Injection ◽  
Water Fraction ◽  
Water Cut

AbstractA method based on the concept of exergy-return on exergy-investment is developed to determine the energy efficiency and CO2 intensity of polymer and surfactant enhanced oil recovery techniques. Exergy is the useful work obtained from a system at a given thermodynamics state. The main exergy investment in oil recovery by water injection is related to the circulation of water required to produce oil. At water cuts (water fraction in the total liquid produced) greater than 90%, more than 70% of the total invested energy is spent on injection and lift pumps, resulting in large CO2 intensity for the produced oil. It is shown that injection of polymer with or without surfactant can considerably reduce CO2 intensity of the mature waterflood projects by decreasing the volume of produced water and the exergy investment associated with its circulation. In the field examples considered in this paper, a barrel of oil produced by injection of polymer has 2–5 times less CO2 intensity compared to the baseline waterflood oil. Due to large manufacturing exergy of the synthetic polymers and surfactants, in some cases, the unit exergy investment for production of oil could be larger than that of the waterflooding. It is asserted that polymer injection into reservoirs with large water cut can be a solution for two major challenges of the energy transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 intensity of oil production (more and cleaner energy).

Sulfide Scale Control in Produced Water Handling and Injection Systems: Best Practices and Global Experience Overview

2014 ◽  
Author(s):  
Jonathan J. Wylde
Keyword(s):  
Best Practices ◽  
Case History ◽  
Iron Sulfide ◽  
Produced Water ◽  
Water Injection ◽  
Scale Formation ◽  
Cutting Edge ◽  
Injection System ◽  
Flow Assurance ◽  
Water Handling

AbstractIron sulfide scale is found almost ubiquitously in maturing oilfield produced water handling and injection systems. Keeping injection systems clean of sulfide scale is becoming more of a shared challenge, but there are few examples where true root cause analysis has led to specific laboratory testing and development of bespoke removal and prevention methods. This paper aims to link these aspects by sharing the best practices from around the world with cutting edge techniques and chemistries used to maintain flow assurance and injectivity in produced water handling systems affected by iron sulfide scale.Discussion includes root causes analysis of iron sulfide scale formation and deposition mechanisms focusing on the interplay of pH, along with sources of iron and sulfide. The paper goes onto discuss laboratory and field evaluation of control methods. Finally, the root causes of iron sulfide scale formation and deposition mechanism, including the relative advantages and merits of the different techniques, including: Chelating agents (for iron sequestration)Surfactants (for water wetting)Biocide (to target SRB and biofilm)Corrosion inhibitor (to lower iron in system)Sulfide scale inhibitors (threshold inhibition of scale)Additionally, case histories are used to elaborate the theoretical discussion. The first case history is from an offshore oilfield water injection system, where fouling occurred due to changes in the flow assurance strategy further upstream and capture the lessons learned on the interplay of different production chemicals. The second case history concerns an onshore oilfield with a vast water injection system of over 3,000 wells supporting approximately 5,000 production wells.The paper concludes with a summary of the decades of experience of solving the most challenging sulfide scaling scenarios, as well as cutting-edge research on a new class of polymeric exotic sulfide scale inhibitor dispersant, effective as threshold concentrations against even lead and zinc sulfide.

Improved oil recovery by raw water injection using horizontal wells

2009 ◽  
Vol 49 (1) ◽  
pp. 453
Author(s):  
Pavel Bedrikovetsky ◽  
Mohammad Afiq ab Wahab ◽  
Gladys Chang ◽  
Antonio Luiz Serra de Souza ◽  
Claudio Alves Furtado
Keyword(s):  
Oil Recovery ◽  
Filter Cake ◽  
Produced Water ◽  
Water Injection ◽  
Horizontal Wells ◽  
Water Flooding ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
The North ◽  
Reservoir Simulator

Injectivity formation damage with water-flooding using sea/produced water has been widely reported in the North Sea, the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid/liquid particles by the rock with consequent permeability decline; it is also due to the formation of a low permeable external filter cake. Yet, moderate injectivity decline is not too damaging with long horizontal injectors where the initial injectivity is high. In this case, injection of raw or poorly treated water would save money on water treatment, which is not only cumbersome but also an expensive procedure in offshore projects. In this paper we investigate the effects of injected water quality on waterflooding using horizontal wells. It was found that induced injectivity damage results in increased sweep efficiency. The explanation of the phenomenon is as follows: injectivity rate is distributed along a horizontal well non-uniformly; water advances faster from higher rate intervals resulting in early breakthrough; the retained particles plug mostly the high permeability channels and homogenise the injectivity profile along the well. An analytical model for injectivity decline accounting for particle capture and a low permeable external filter cake formation has been implemented into the Eclipse 100 reservoir simulator. It is shown that sweep efficiency in a heterogeneous formation can increase by up to 5% after one pore volume injected, compared to clean water injection.

Sign in / Sign up

Export Citation Format

Share Document