This paper describes some of the operational aspects, planning practices and improvements in both coil tubing and bullhead acid stimulation campaigns carried out to increase the performance of gas-producing wells in a mature sour-gas asset. The objective of the campaign was to reduce operational costs by flowing the wells back directly into the production facilities after the treatment, without the use of temporary production test equipment. This strategy would be considered successful, if it could be proven to be technically well-executed, and compliant with HSSE directives. By engaging in a multi-disciplinary approach, critical aspects of this campaign were identified at an early stage, including selection of fit-for-purpose stimulation formulation. Furthermore a novel corrosion inhibitor capable of withstanding unspent acid in a sour system was deployed in the facilities for integrity and protection.
Key performance indicators for the campaign were set, including target pH values for flowback samples. Monitoring of H2S concentration of the produced gas was carried out, and control with the use of a H2S scavenger injected in well flowlines allowed for export gas specifications to be maintained. Overall the campaign generated significant productivity improvements. This cost-effective acid stimulation is therefore a valuable tool for well reservoir and facilities management in the asset.
Shepherd, Andrew G. (Shell Upstream International Europe) | Mcgregor, Stuart (Shell) | Trompert, Ruud A. (Shell Intl. E&P BV) | Ubbels, Sen (Champion Technologies BV) | Van De Gender, Bob (Champion Technologies) | Van Ommen, Theodor Hendrik (Champion Technologies) | Van Der Knoop, Sjoerd (Champion Technologies BV)
This paper describes the production chemistry management process undertaken during the design, commissioning and start-up phases of the Schoonebeek redevelopment. Challenging separation issues, saline water, together with a multitude of other process conditions, resulted in complex, but robust application portfolio. This was established during the design stages of the project. Early involvement of the production chemistry discipline aided this process. Chemical selection was conducted in adherence to HSSE directives and focusing on unique produced fluid properties. Since start-up, the success of chemical performance has been due to the availability of chemical treatment programs and surveillance/sampling plans. No contingency chemicals have so far been needed at the facilities since start-up. Export oil and water key performance indicators have been for the majority of the time met. Further optimization of chemical applications is an ongoing process which will follow the life of the field.
The Schoonebeek oilfield was discovered in 1943 and operated until the late nineties. Details of the reservoir and past production history have been discussed previously1,2. A number of enhanced oil recovery methods were trialed in this field ranging from high and low pressure steam floods, hot water floods and in situ combustion3,4,5. The field is now being redeveloped, using low pressure steam flood with horizontal wells1. Information on the current selected recovery method and the injection and production profiles are reported elsewhere1. Superheated steam, supplied by a Combined Heat and Power (CHP) plant will be injected into the reservoir via 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir via 44 horizontal wells in 18 locations using artificial lift pumps, with a Casing Vapour Recovery (CVR) System included to improve the gross lifting capability. Production from each wellsite location will be routed via a gross gathering system to the Central Treating Facilities (CTF). The CTF will include the required facilities to separate the oil, water and associated gas production and treat the respective streams to export quality. The treated oil is evacuated via pipeline to refining in Germany1. The produced water is exported and injected into depleted gas wells in different fields2. In later field life as wells warm up, the casing vapour will be spiked back into the gross production line. Cold production wells located furthest away from the CTF will be subsequently segregated from warm production wells by routing them to the CTF via the CVR pipeline. Vapour separated from the oil in the CTF will be used as fuel gas in the CHP plant which is adjacent to the CTF. Together with heat integration between the CTF and CHP this minimizes energy consumption, CO2 emissions and heat losses to atmosphere from the two facility locations. Fit for purpose chemical management is very important in all stages of a project from concept select to start-up6. This is even more critical in heavy oil systems which offer very unique challenges. This paper discusses some of the technical production chemistry issues associated with the Schoonebeek redevelopment. It should be highlighted that chemical management is a continuous improvement activity, based on careful surveillance and understanding of well and facilities performance.
This paper describes the chemical control and integrity management steps taken during the commissioning and start-up of the Combined Heat and Power plant (CHP) of a large field redevelopment. The chemical controls were carried out using a combination of new and established chemistries in oxygen scavenging, corrosion inhibition and scale inhibition. Carefully designed passivation and slugdosing, in addition to a clear and robust sampling and analysis plan, had a direct impact on the development of these operations. The lessons learned of two boiler systems are discussed together with the improvements implemented to achieve fit for purpose steam generation. This has included for instance, particular attention on the monitoring of boiler feed water quality and use of hydrogen meters. Furthermore magnetite formation was established for two boiler systems. This was confirmed by pH trends in the high pressure drums, sample appearance, hydrogen measurements and analysis of solids taken during various stages of monitoring. The results suggest that magnetite formation occurred at conditions different to what is the established rule of thumb during high pressure start-ups, e.g. 30 bar. It is speculated that such behavior was influenced by the chemical control selected. Key performance indicators (e.g. phosphate operational window) as well as automated chemical dosing is allowing good integrity control of the steam generation system as the facility migrates into steady state operation.
The Schoonebeek oilfield in the Netherlands is being redeveloped using the Gravity Assisted Steam Flooding (GASF) thermal production method to improve oil recovery1. Superheated steam, supplied by a Combined Heat and Power (CHP) plant will be injected into the reservoir via 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir via 44 horizontal wells in 18 locations using artificial lift pumps, with a Casing Vapour Recovery (CVR) System included to improve the gross lifting capability. Production from each wellsite location will be routed via a gross gathering system to the Central Treating Facilities (CTF). The CTF will include the required facilities to separate the oil, water and associated gas production and treat the respective streams to export quality. In later field life as wells warm up, the casing vapour will be spiked back into the gross production line. Cold production wells located at the border will be subsequently segregated from warm production wells by routing them to the CTF via the casing vapour recovery pipeline. Vapour separated from the oil in the CTF will be used as fuel gas in the CHP plant which is adjacent to the CTF. Together with heat integration between the CTF and CHP this minimizes energy consumption, CO2 emissions and heat losses to atmosphere from the two facility locations. Steam distribution plays a key role in the project. Chemical control and integrity management during the commissioning, start-up and steady state operation of the steam facilities is the subject of this case history paper.
Shepherd, Andrew G. (Nederlandse Aardolie Maatschappij BV) | van Dijk, Menno (Shell Global Solutions Intl BV) | Koot, Wouter (Shell Global Solutions) | Dubey, Sheila Teresa (Shell Global Solutions) | Poteau, Sandrine (Shell) | Zabaras, George John (Shell Global Solutions) | Grutters, Mark (Shell)
This paper presents an overview of the different flow assurance issues associated with naphthenic acids. In field development projects a good understanding of naphthenic acid phase behavior is essential to avoid unplanned plant changes and deferment. Good data on naphthenic acid content and speciation is obtained by using a representative sample. Basic measurements (e.g. TAN) are not sufficient to obtain a detailed understanding of the flow assurance issues regarding a particular crude oil. Infrared spectroscopy and mass spectrometry, high and low resolution, are the preferred tools for analysis of crude oils. The target naphthenic acid species, e.g. ARN or fatty acids will dictate the best suited method selected for analysis. Geochemical analysis of crude oils has helped to highlight some common features which can be used for prediction purposes. For bound soap scale-forming crude oils, a large amount of complexed acids result in emulsions which are difficult to break. Chemical treatments are needed and these should be identified early in the project stages. For soap scale-forming crude oils chemical treatment requires in depth analysis of topsides equipment and impact on existing chemical portfolio. Surveillance of soap scale-forming crude oils is possible using readily available equipment. For soap emulsion-forming crude oils, paraffin precipitation adds to the stability of the emulsion formed. Chemical treatment and heat is required for best results. Use of stock tank sample properties can be used for predictions regarding the type of naphthenic acid issue to be expected for particular crude oil sets.
Naphthenic acids play an important role in upstream and downstream oilfield activities in many diverse areas such as exploration geochemistry and corrosion. In E&P field developments within the discipline of flow assurance, the effects of naphthenic acids in crudes and condensate systems have been specifically reported in emulsion stabilization, formation of soaps, enhanced oil recovery performance and in natural hydrate inhibition1-5. The impact of naphthenic acids on facilities design cannot be underestimated. Most issues are treated with chemical solutions, and this affects CAPEX as well as OPEX. Thus there should be robust protocols to ensure naphthenic acids are correctly identified in conjunction with the other reservoir fluid properties as early as possible. By taking these steps, costly retrofitting or plant changes and deferment can be avoided. This work will review lessons learned to better understand the properties of naphthenic acids systems and their flow assurance impact. This will include a discussion on different related case histories. It should be mentioned that the impact of naphthenic acids should be studied on a field by field basis with a fit for purpose approach.
Barnes, Julian Richard (Shell Global Solutions) | Groen, Khrystyna (Shell Global Solutions) | On, An (Shell Global Solutions International BV) | Dubey, Sheila Teresa (Shell Global Solutions) | Reznik, Carmen (Shell Oil Co.) | Buijse, Marten Adriaan (Shell Exploration & Production) | Shepherd, Andrew G. (Nederlandse Aardolie Maatschappij BV)
In this paper an innovative structure/property approach is used to evaluate several commercially available surfactants in tests relevant to both alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) floods, in order to gain an understanding of how hydrophobe structure is related to surfactant performance and crude oil composition. The surfactant structural elements considered here include relative branching level and carbon chain length. This has application to chemical EOR implementation in fields over a range of reservoir temperatures and salinity. Phase behavior (giving interfacial tension), and micro-emulsion viscosity tests were carried out for internal olefin sulfonates and mixtures with alcohol propoxy sulfates to identify those that perform well while minimizing or eliminating the use of costly co-solvents. Hydrophobe branching and carbon chain length, characterized by gas chromatography, were used to match surfactants to certain crude oil properties such as natural surfactants, including total acid number (TAN) and asphaltenes, and the ratio of saturates/aromatics. The paper also examines how crude oil sampling influences crude properties and surfactant performance. The approach used and associated data contribute to cost reduction of formulations through a) better matching of commercially produced surfactants to the reservoir and crude oil properties to improve oil recovery efficiency, and b) minimizing or eliminating the use of co-solvents to reduce formulation and logistics costs. In addition, the study demonstrates how binary blends from a few core surfactants can match formulations across regionally different crude oils thereby simplifying formulation selection, and reducing uncertainty and cost.
Due to favorable economics and advances in technology, enhanced oil recovery (EOR) techniques are being revisited for a variety of industry projects. Surfactant based EOR is receiving particular attention because the technique is seen to have great potential for mobilizing residual oil in reservoirs1. In this technique mobilization of residual oil is achieved through use of surfactants that generate a sufficiently (ultra) low crude oil/water interfacial tension (IFT) to overcome capillary forces and allow the oil to flow2.
Since reservoirs have different characteristics including temperature and crude oil and water composition, the surfactant structures of an ASP/SP formulation need to be tailored for a reservoir on a case by case basis. In addition, a promising formulation must satisfy important criteria including low adsorption, good aqueous solubility and thermal/hydrolytic stability. Economic criteria such as acceptable cost/performance ratio and commercial availability of surfactants are also pre-requisites for pilots and full field floods. Consideration also needs to be given to the separation of the produced fluids.