Produced Water Disposal in Deep Aquifers: Case History Review of Ughelli East-30 Pilot Injector

2021 ◽  
Author(s):  
Osode Peter ◽  
Oluwatoyin Olusegun ◽  
Temitayo Ologun ◽  
Obinna Anyanwu
Keyword(s):  
Produced Water ◽  
Water Injection ◽  
Injection System ◽  
Composition Analysis ◽  
Well Completion ◽  
Deep Aquifers ◽  
Water Composition ◽  
Sand Control ◽  
Well Injectivity ◽  
Sandstone Formation

Abstract A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area. The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated. The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations. Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.

Field Experiences Detailing Acrolein (2-propenal) Treatment of a Produced Water Injection System in the Sultanate of Oman

2009 ◽  
Author(s):  
Darin D. Horaska ◽  
Joseph E. Penkala ◽  
Curtis A. Reed ◽  
Melissa D. Law ◽  
Simon Gaffney ◽  
...  
Keyword(s):  
Produced Water ◽  
Water Injection ◽  
Field Experiences ◽  
Injection System ◽  
Sultanate Of Oman

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.

Produced Water Debottlenecking Delivers Low Cost Incremental Production for the Pyrenees FPSO

2021 ◽  
Author(s):  
Paul Elliott ◽  
Melissa Gilbert
Keyword(s):  
Produced Water ◽  
Low Cost ◽  
Water Injection ◽  
Oil Production ◽  
Late Life ◽  
Lessons Learned ◽  
Injection System ◽  
Value Drivers ◽  
Risk Approach ◽  
Oil Tanks

Abstract The Pyrenees FPSO development, located offshore Western Australia, produced first oil in 2010. By 2017, the topsides facility had became constrained by produced water production, reaching the facility design capacity of 110,000 bbl/d. A strong business driver was presented to debottleneck the water processing train to increase oil production, for which a holistic, system-wide approach was required. A series of brownfield debottlenecking scopes were identified and assessed using a systematic value versus risk approach. The key value drivers were recognised as incremental oil production, execution timing and cost. The assessment focused on improving Produced Water Re-Injection (PWRI) pump throughput and uptime, optimising the produced water treatment and overboard discharge systems, and the use of cargo oil tanks for separation. Project execution was phased to allow early debottlenecking gains to be unlocked as major modification scopes were progressed. The most capital intensive project executed was the installation of a side-stream Compact Flotation Unit package to polish and discharge produced water overboard. In combination, the projects delivered a 36% increase in produced water handling capacity to 150,000 bbl/d, accelerating 8.5% production over a 3-year period. In addition, the projects increased facility uptime by 1.8% and reduced the risk of late-life produced water injection system failures. This case study illustrates a logical and systematic approach to production debottlenecking, resulting in a significant production uplift, safely delivered for low relative CAPEX investment. The processes described and lessons learned in this project may be applicable to other maturing fields and facilities, and can be used to assist resolving late-life produced water challenges.

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

Nanotechnology Helps Decrease Pressure, Increase Injection in Offshore China Oil Field

2021 ◽  
Vol 73 (09) ◽  
pp. 58-59
Author(s):  
Chris Carpenter
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Gas Production ◽  
Oil Field ◽  
Water Flooding ◽  
Injection System ◽  
Bohai Bay ◽  
Reservoir Properties ◽  
Positive Effects ◽  
Offshore Technology

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30407, “Case Study of Nanopolysilicon Materials’ Depressurization and Injection-Increasing Technology in Offshore Bohai Bay Oil Field KL21-1,” by Qing Feng, Nan Xiao Li, and Jun Zi Huang, China Oilfield Services, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Nanotechnology offers creative approaches to solve problems of oil and gas production that also provide potential for pressure-decreasing application in oil fields. However, at the time of writing, successful pressure-decreasing nanotechnology has rarely been reported. The complete paper reports nanopolysilicon as a new depressurization and injection-increasing agent. The stability of nanopolysilicon was studied in the presence of various ions, including sodium (Na+), calcium (Ca2+), and magnesium (Mg2+). The study found that the addition of nanomaterials can improve porosity and permeability of porous media. Introduction More than 600 water-injection wells exist in Bohai Bay, China. Offshore Field KL21-1, developed by water-flooding, is confronted with the following challenges: - Rapid increase and reduction of water-injection pressure - Weak water-injection capacity of reservoir - Decline of oil production - Poor reservoir properties - Serious hydration and expansion effects of clay minerals To overcome injection difficulties in offshore fields, conventional acidizing measures usually are taken. But, after multiple cycles of acidification, the amount of soluble substances in the rock gradually decreases and injection performance is shortened. Through injection-performance experiments, it can be determined that the biological nanopolysilicon colloid has positive effects on pressure reduction and injection increase. Fluid-seepage-resistance decreases, the injection rate increases by 40%, and injection pressure decreases by 10%. Features of Biological Nanopolysilicon Systems The biological nanopolysilicon-injection system was composed of a bioemulsifier (CDL32), a biological dispersant (DS2), and a nanopolysilicon hydrophobic system (NP12). The bacterial strain of CDL32 was used to obtain the culture colloid of biological emulsifier at 37°C for 5 days. DS2 was made from biological emulsifier CDL32 and some industrial raw materials described in Table 1 of the complete paper. Nanopolysilicon hydrophobic system NP12 was composed of silicon dioxide particles. The hydrophobic nanopolysilicons selected in this project featured particle sizes of less than 100 nm. In the original samples, a floc of nanopolysilicon was fluffy and uniform. But, when wet, nanopolysilicon will self-aggregate and its particle size increases greatly. At the same time, nanopolysilicon features significant agglomeration in water. Because of its high interface energy, nanopolysilicon is easily agglomerated, as shown in Fig. 1.

Transforming Water Injection Process With Real Time Automation

2021 ◽  
Author(s):  
Muhammad Zakwan Mohd Sahak ◽  
Eugene Castillano ◽  
Tengku Amansyah Tuan Mat ◽  
Maung Maung Myo Thant
Keyword(s):  
Oil Recovery ◽  
Capital Investment ◽  
Water Injection ◽  
Optimal Operation ◽  
Near Miss ◽  
Injection System ◽  
Injection Technique ◽  
Manual Operation ◽  
Injection Process ◽  
Oil Rim

Abstract For mature fields, water injection is one of the widely deployed techniques to ensure continuous oil recovery from the reservoir by maintaining the reservoir pressure, oil rim and pushing the oil from injection to production wells. Thus, it is critical to ensure a continuous and reliable operation of water injection to have consistent and sustainable rate. This paper demonstrates the new approach, utilizing automation and digital technology providing operational improvement and reduction in unplanned production deferment (UPD). One of the methods to effectively manage the water injection operation is via automation of injection process, especially since most of the water injection facilities still rely heavily on manual operation. First, a discussion on typical water injection technique is discussed. Challenges and sub-optimal operation of water injection processes within the company and industry are analysed. Then, the designing of a fully automated water injection system, such as equipment availability and constraints in matching and responding to well injection requirement are demonstrated. While an immediate adoption of process automation to mature assets may be faced with challenges such as system readiness, hardware availability, capital investment and mindset change, a step-by-step approach such as guided operation and semi-auto operation is explored as preparation prior to a full automation roll-out. With the shift from manual operation reliance to automation, the response time to process changes is improved leading to reduction in near-miss and trip cases, and minimum unplanned deferment.

Effective Treatment of Humic Acid Foulants in SAGD Produced Water

2021 ◽  
Author(s):  
Chunli Li ◽  
Zhiwei David Yue ◽  
Xiaohong Tian ◽  
John Hazlewood
Keyword(s):  
Humic Acid ◽  
Humic Acids ◽  
Produced Water ◽  
Chelating Agent ◽  
Cost Effective ◽  
Efficiency Factor ◽  
Alcohol Ethoxylate ◽  
Major Type ◽  
Chemical Solution ◽  
Well Injectivity

Abstract Humic acids, one major type of organic foulants in steam assisted gravity drainage (SAGD) produced water, can precipitate on surface and downhole equipment in SAGD facilities, resulting in high cleaning costs, potential equipment damage and decrease of injectivity of disposal wells. In this paper, a cost-effective chemical solution is presented where an alcohol ethoxylate surfactant/chelating agent package can efficiently disperse the organic fouling molecules in SAGD produced water; therefore, the approach is expected to significantly mitigate the humic acid related fouling issues in the SAGD system. In this study, a variety of commercially available surfactant products were evaluated for their aids in well injectivity on humic acid molecules in the freshly obtained SAGD produced water. The lab testing filtration apparatus was specially designed to simulate the sandstone formation geology of SAGD disposal wells. An "efficiency factor" was defined to grade the dispersing performance of the surfactant and/or surfactant/chelating agent package in the lab filtration tests. The efficiency factor provides a reasonable estimation regarding how well the chemical can reduce the plugging risk in a disposal well as compared to the untreated produced water. Among all the surfactant products tested, an alcohol ethoxylate surfactant with the appropriate molecular structure shows distinguished dispersing performance on humic acids in SAGD produced water. However, the surfactant alone was found inconsistent in the dispersing performance when different batches of the produced water were involved. Inclusion of the specific metal chelating agents to the above surfactant formulation improved the dispersing performance consistency. The chelator molecules presumably help destroy the intermolecular bridges among humic acid molecules in the SAGD produced water; thereby, increasing the dispersing effectiveness of the alcohol ethyoxylate surfactants. Tests show that the efficiency factor of the surfactant/chelating agent package is higher than 8, which implies that the formulation could lead to eight times extension of the interval between workovers on SAGD disposal wells, a significant reduction for the operational downtime and costs. This study presented a cost-effective chemical solution to help disperse the humic acid molecules in SAGD produced water, which can help significantly reduce the fouling risk caused by organic foulants, improve injectivity and extend the intervals between workovers of SAGD disposal wells.

scholarly journals Investigation of Water Composition on Formation Damage and Related Energy Recovery from Geothermal Reservoirs: Geochemical and Geomechanics Insights

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7415
Author(s):  
Ilyas Khurshid ◽  
Imran Afgan
Keyword(s):  
Geothermal Energy ◽  
Water Injection ◽  
Formation Damage ◽  
Breakdown Pressure ◽  
Geothermal Reservoirs ◽  
Water Composition ◽  
Porosity Reduction ◽  
Reduction Case ◽  
Formation Porosity

The main challenge in extracting geothermal energy is to overcome issues relating to geothermal reservoirs such as the formation damage and formation fracturing. The objective of this study is to develop an integrated framework that considers the geochemical and geomechanics aspects of a reservoir and characterizes various formation damages such as impairment of formation porosity and permeability, hydraulic fracturing, lowering of formation breakdown pressure, and the associated heat recovery. In this research study, various shallow, deep and high temperature geothermal reservoirs with different formation water compositions were simulated to predict the severity/challenges during water injection in hot geothermal reservoirs. The developed model solves various geochemical reactions and processes that take place during water injection in geothermal reservoirs. The results obtained were then used to investigate the geomechanics aspect of cold-water injection. Our findings presented that the formation temperature, injected water temperature, the concentration of sulfate in the injected water, and its dilution have a noticeable impact on rock dissolution and precipitation. In addition, anhydrite precipitation has a controlling effect on permeability impairment in the investigated case study. It was observed that the dilution of water could decrease formation of scale while the injection of sulfate rich water could intensify scale precipitation. Thus, the reservoir permeability could decrease to a critical level, where the production of hot water reduces and the generation of geothermal energy no longer remains economical. It evident that injection of incompatible water would decrease the formation porosity. Thus, the geomechanics investigation was performed to determine the effect of porosity decrease. It was found that for the 50% porosity reduction case, the initial formation breakdown pressure reduced from 2588 psi to 2586 psi, and for the 75% porosity reduction case it decreased to 2584 psi. Thus, geochemical based formation damage is significant but geomechanics based formation fracturing is insignificant in the selected case study. We propose that water composition should be designed to minimize damage and that high water injection pressures in shallow reservoirs should be avoided.

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