Summary This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.

Carbon capture and storage (CCS) is recognized as an important technology in the decarbonisation of the energy system and saline aquifers are potential geological storage candidates. A major integrated feasibility study was conducted to screen and rank carbonate saline aquifer candidates for subsurface CO2 storage, onshore Abu Dhabi. The objectives were to obtain a range of potential CO2 storage capacities and annual injection rates and establish CO2 technical feasibility by integrating subsurface, well performance, cap rock integrity and economic analysis. A candidate screening matrix was developed taking into account onshore Abu Dhabi saline aquifer geological characteristics. Saline aquifers "A" and "B" within the syncline area were among the highest ranked candidates. A large-scale 3D static model was developed, utilising seismic and well data. Extensive CO2 storage simulation runs were performed, covering sensitivities and capturing major storage process/mechanisms applicable to carbonate formation. Combining geomechanics, geoscience, well performance, integrity and dynamic modelling, a CO2 storage site design was completed with slanted/horizontal injectors drilled radially from a centralised well pad. Ranges of CO2 storage capacity and maximum injection rates were obtained, depending on number of injectors and accounting for water offtake in nearby areas. Additionally, CO2 plume migration within several tens of thousands of years was simulated to aid CO2 containment assurance. Separate studies were performed to locate potential CO2 storage surface sites and used as part of the input for CO2 pipeline and surface facilities high level design. CAPEX, OPEX and abandonment cost estimates were generated as input for economic analysis. A multi-disciplinary risk assessment was performed, identifying potential risk factors throughout the life cycle of CO2 storage. De-risking and mitigation measures were considered and a detailed measurement, monitoring and verification (MMV) plan was developed. This paper presents the first integrated study on saline aquifer CO2 storage technical feasibility in this syncline area. A novel integrated workflow is employed, from initial candidate screening through dynamic modelling, surface facilities and risk assessment to recommendations for additional data acquisition. Key aspects which improved on published major international CO2 sequestration assessments are highlighted. The results and conclusions offer valuable insights for other Operators considering or planning CO2 sequestration in saline aquifer projects.

CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies. To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir's main production unit. Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable. Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields. When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation. Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water. The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated. Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy. This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.

Abstract Key criteria such as initial skin, permeability, scaling, water quality and temperature are the typical considerations employed by most injectivity or formation damage investigations, however it is our belief that this is simply not enough. Other mechanisms and their combined or secondary effects are typically underestimated, which leads in many cases to the application of mitigation and remediation techniques, which, although initially effective, are short lived due to an inadequate understanding of the formation damage/well communication impairment mechanisms present. The cause(s) of injectivity decline may be numerous; and are frequently interlinked. This paper examines the considerations of a holistic workflow for defining the potential cause(s) of injectivity decline. Standard considerations of the workflow include physical and chemical water treatment process, water quality and its degradation between process and sand face, flow assurance, physical and chemical interactions with the sandface and near wellbore, mineralogical interactions, microbiological influences and completion architecture. Such approaches have found value in defining potential causes of injectivity decline, and appropriate remediations or mitigations throughout Sub-Saharan Africa, and Europe.

Reservoir souring is simply defined as the predicted or observed increase in production of sulphide in oil, water or gas phase. The potential causes are far less simply defined, and can, in many cases, lead to a significant disruption to operations through concerns over HS&E, integrity and process efficiency. The consequences of sour production can be far reaching, and almost always expensive, perhaps to the point of making a field un-economical to produce. One of the reasons for this is that, in many cases the response to souring is to mitigate, long term and short term, the consequences of souring, rather than the cause of souring. This paper examines the application of both high level and detailed investigation workflows which have led to significant improvements in understanding both the risks associated with souring and the most techno-economically feasible long term and short term mitigations of both causes and effects. The aim of the workflow is to define causes and develop solutions to either mitigate souring and/or the effects of souring, maximising the techno-economic benefit to the operator and reducing HS&E risks as much as possible. The workflows themselves are phased and flexible, they aim to examine pre-existing data, examine their validity, and/or collect new data to identify the probable causes of souring in each specific case. Once the cause(s) have been defined it then becomes possible to estimate worst case souring potential and integrity threat based upon biochemical and geochemical interactions, phase behaviours and the physical condtions for either microbiological and/or non-microbiological throughout the system. This approach has been applied numerous times to great effect in sub-sahran Africa, North America and Europe.

CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields’ water injection system.

Abstract A well intervention can be a significant cost during a well's lifetime because it entails lost production, caliper surveys, rigging up expensive workover equipment and possesses HSE risks. These high costs impact the operations of mature fields, especially during market downturns. To address the cost effectiveness of well workover activities, an integrated strategy was developed utilising corrosion, erosion and tubing stress analyses. The approach aims to defer unnecessary well interventions and efficiently control budgets using prioritisation of integrity-related well operations. The proposed holistic workflow for integrity management is based upon the application of well modelling, corrosion, erosion and tubing stress analyses. These elements utilise industry-standard equations and principles to evaluate the potential for integrity loss. The corrosion analyses are based upon the corrected de Waard Milliams correlation, measured corrosion rates and the application of equations of state and thermodynamics to calculate hydrogen sulphide partitioning if sour conditions are prevalent. Well performance modelling is linked with corrosion analyses where factors such as production rate forecasts, flow velocities, water alkalinity, tubing profile and PVT data are considered. Erosion is an important factor that impacts metallurgy longevity. To calculate erosion rates along production tubing, erosion analyses are supported and correlated with empirical data specific to individual pipe geometry and the metal behavior when contacted by particles in specific flow regimes. Stress analyses calculates various tubing safety factors (burst, collapse, axial and triaxial) to assess the time, mechanism and risk of tubing failure using production rate forecasts, wall thickness and metal loss results obtained from corrosion and erosion analyses. Because of the complexity of corrosion, corrosion prediction models can significantly over-estimate corrosion rates by several orders of magnitude. Tuning prediction models to caliper data accounts for field-specific factors, e.g. hydrocarbon properties and scale deposition, significantly improve the accuracy of subsequent predictions and increase confidence in well-integrity-review results. This workflow enables operators to control and balance capital (CAPEX) and operational expenditure (OPEX) related to completions and maintenance by enabling them to more accurately predict failures, plan work-over operations and assess the most cost-effective strategy.

Abstract An Excel-based tool was developed that utilizes cubic equation of state (EOS) and thermodynamic electrolyte chemistry modelling. The software enables operators to assess sour production streams from a reservoir, through production tubing, pipelines and facilities to an export pipeline within a range of temperature and pressure conditions. The tool enables quick and accurate sour-production- stream assessment, improving the operator's understanding of the H2S- related integrity risks to ensure safe and stable production. The tool is designed to support materials of construction suitability reviews and provide input to optimize scavenger applications, using the most at-risk components and/ or locations in the system to determine if wells and facilities are safe to operate under current conditions. This development represents a unique combination of functionality because it combines three elements to derive accurate partition coefficients across a range of operational conditions and gas/liquid compositions: thermodynamic modelling of water chemistry; equation-of-state hydrocarbon modelling; and the basic physical principles at work in production streams. The approach is employed to assess the integrity risk posed to system components on Chevrons' Alba field in the North Sea. At the time of the modelling, the asset team planned to bullhead three production wells with base oil because of the significant well integrity concerns resulting from high H2S levels. The ability to quickly determine accurate partial pressure and sulphide partitioning profiles for the three production wells ultimately led to the wells remaining open, and saving the operator from deferring in excess of 3,000 bbl/day of oil production from the at-risk wells. The modelling results were confirmed by a third-party analysis of sulphide concentrations in three phases in the test separator, indicating that the calculated total sulphide per-unit-volume in the system was correct, and the partial-pressure and three-phase concentration profiles for each well were also correct. The tool was developed so that non chemists, field personnel, engineers and any other relevant stakeholders can make their own integrity assessments.

Abstract The use of horizontal wells for injection and production to help maximise the sweep efficiency and economic recovery; especially for recovery of viscous oil in offshore environments. Flow control devices (FCDs) are readily used to control the flow along the well in conventional recovery operations leading to improved recovery efficiency. The benefits of polymer flooding and FCDs has been well demonstrated, however the combination of the two technologies has yet to be fully realised. The cause of FCDs not being as utilised in polymer injection application is due to the severe degradation of the polymer through devices. This paper provides a workflow used to determine the benefits of a well planned and executed polymer injection complemented by the optimum flow control strategy. The main focus will be on demonstrating the relative weights in the objective function of optimising the sweep efficiency with the cost of reduced polymer quality. This workflow will allow a number of strategies to be studied, such as the impact of well types, well placement, well lengths, FCDs and polymer viscosities. The impact of polymer viscosity reduction in an injector well with FCDs is of particular interest. Hence the trade-off of the polymer degradation and the ability to get the required polymer quantity in the various segments of the well will be described. The feasibility of polymer flooding with flow control is a viable alternative for classical enhanced oil recovery (EOR) but the decision whether or not to implement it has to be based on prudent analysis and decision making process. Hence the study highlights the importance of understanding uncertainties with control as well as those associated with reservoir and geology.