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Oil and gas extraction using water has opened up new hydrocarbon resources. However they can produce four times more salty water byproduct than oil. Desalination in shale gas and polymer-flood EOR remain niche markets for lowering cost and improving production. Aker Solutions and FSubsea have agreed to a joint venture, named FASTSubsea, to help operators increase oil recovery. High-concentration polymer flooding can improve oil-displacement efficiency but separation of oil/water mixture becomes more difficult because of emulsification.
The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. The complete paper presents steps to accelerate enhanced oil recovery (EOR) in a Grimbeek field from a four-injector pilot to 80 new injectors in a rapid deployment. The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the break-even level of operations and evaluate the results. This paper summarizes a technology using SMP to provide downhole sand control in openhole environments. With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable addition of new ones.
Conventional and unconventional hydrocarbons are likely to remain the main component of the energy mix needed to meet the growing global energy demand in the next 50 years. The worldwide production of crude oil could drop by nearly 40 million B/D by 2020 from existing projects, and an additional 25 million B/D of oil will need to be produced for the supply to keep pace with consumption. Scientific breakthroughs and technological innovations are needed, not only to secure supply of affordable hydrocarbons, but also to minimize the environmental impact of hydrocarbon recovery and utilization. The lifecycle of an oilfield is typically characterized by three main stages: production buildup, plateau production, and declining production. Sustaining the required production levels over the duration of the lifecycle requires a good understanding of and the ability to control the recovery mechanisms involved. For primary recovery (i.e., natural depletion of reservoir pressure), the lifecycle is generally short and the recovery factor does not exceed 20% in most cases.
Researchers from Chevron are looking into a new approach to understand the drivers of polymer hydration. How might this affect the design of mixing systems in the field, and could it affect offshore EOR applications? Fluid Efficiency and Rhapsody Venture will partner to refine and launch a new molecular technology to improve the flow in pipelines. In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them. This is the first of several articles on the subject of water management for unconventional hydraulic fracturing.
Its reward for years of struggling to adapt to low prices and weak demand for its oil and gas has been an epic crash. Canadians selling change say it is time to consider possibilities that seemed inconceivable in the past. So many unprecedented changes have occurred in the Canadian oil business that it is impossible to compare the current downturn to anything seen before. The savings result in part from the depreciation of global currencies against the US dollar, as most operating expenses in oil and gas production are realized in local currencies. Financial Fallout: For two big companies, tougher times call for tougher actions.
Responsibilities included EOR screening, laboratory design and coreflood studies, and reservoir characterization for EOR. Advice and input given on pilot design, facilities design, field application, and surveillance and monitoring; together with advice and input on simulation of EOR processes and analysis of results.
Kun Xie is currently a PhD candidate majoring in Petroleum & Natural Gas Engineering in Northeast Petroleum University (NEPU) in China. Kun got the bachelor degree in Petroleum Engineering and master degree in Oil & Gas Development Engineering from the NEPU. Kun obtained the qualification of postgraduate in advance for his excellent grade in 2012. During his postgraduate studies, Kun's overall scores ranked 1st in his major. So far, Kun has gotten many honors awarded by the university and the government.
Yue, Zhiwei David (Halliburton) | Chen, Ping (Halliburton) | Draghici, Vlad (Halliburton) | Westerman, Megan (Halliburton) | Huijgen, Martijn (Halliburton) | Privitera, Angelo (Halliburton) | Hazlewood, John (Halliburton) | Hagen, Thomas (Halliburton)
An oilfield operator relies extensively on heat exchangers (Hexs) to break heavy oil emulsions. A workhorse inhibitor worked reliably to control thermally induced scale precipitation caused by local hard waters. However, an upsurge of scale-related Hexs tubing blockage occurred during a harsh winter that coincided with a breakthrough of enhanced oil recovery (EOR) polymer into some water sources. Through comprehensive lab testing, root causes of the failure were identified. A new product was developed featuring superior tolerance to variable production parameters, especially Hexs temperatures.
Scale inhibitor efficacy is strongly influenced by overall scaling conditions including water chemistry, temperature, pressure, and presence of incompatible chemicals. In this study, scale precipitates collected from Hexs were characterized using environmental scanning electron microscopy techniques. New inhibitor chemistries were screened through thermal aging; then evaluated for inhibition performance by dynamic tube blocking methods at temperatures ranging from 42°C to 171°C. An additional performance test was designed for the final candidate to further investigate adverse impacts from the EOR polymer and incumbent scale product if a dual-product treatment is required throughout the field fluid system.
The incumbent effectively inhibited scale formation at ≤120°C but showed reduced performance at 160°C. This result is consistent with field records indicating most tubing blockages occurred during the coldest days when Hexs temperature was raised to 160°C to increase heat to treat fluids. Meanwhile, it also suffered antagonistic effects from the EOR polymer. A dozen new inhibitor chemistries were studied including polymers and phosphonates. Polymeric inhibitors had higher thermal aging ratings but were less compatible with the waters involved. Ideal candidates must have thermal stability, high-temperature inhibition performance, and applicability to wide ranges of operational conditions, including Hexs temperature, water hardness, bicarbonate, and foreign substances. Thus, a single product can be applied to the entire field and simple dosage adjustments can readily handle most expected scaling risks. The new product passed all the criteria and significantly reduced operating and equipment replacement cost since deployment.
This paper provides a unique scaling challenge that combined ultra-high temperature and EOR polymer influence, and a systematic approach to understanding and resolving the issue.
Scale inhibitor (SI) analysis is an extremely important part of scale management and it is essential to have reliable methods for the accurate and precise measurement of scale inhibitor residuals in produced fluids in order to prevent wells from scaling. This information enables key decisions on the efficiency of scale squeeze and continuous chemical injection treatments especially in remote environments. In remote fields, such as in desert and extreme winter environments, the ability to be able to monitor scale squeeze residuals on-site would offer significant potential to improve scale management capability through provision of rapid data which otherwise might not be available for several weeks due to long sample transport times to the laboratory. Since conventional scale inhibitor analysis methods are not suited for on-site analysis this has led to the development of a toolbox of technology options including suitable scale inhibitor squeeze chemistry coupled with advanced, on-site, "near online" scale inhibitor detection procedures including Fluorescence (F) and Time Resolved Fluorescence (TRF). In this paper, two field examples for on-site TRF analysis of polymeric scale squeeze inhibitors from remote wells in harsh environments will highlight the benefits of quick and timely scale inhibitor residual information. In the example from remote desert wells, a comparison of TRF and High Performance Liquid Chromatography (HPLC) analysis of the polymer residuals will show the accuracy and precision of the TRF method at low SI levels. In addition, an example for the proof of concept of detection of three different F Tagged sulphonated polymers in the presence of a phosphonate squeeze inhibitor and continuously injected untagged polymer will demonstrate the ability of "near on line" fluorescence techniques to improve scale management where four subsea wells are co-mingled in the same flow line. This paper concludes that fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules whereas Time Resolved Fluorescence provides the ability to detect untagged scale inhibitors like sulphonated copolymers, phosphonates and phosphate esters.
With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. One key question that is yet to be addressed is the influence of EOR chemicals, such as hydrolysed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime. Squeeze lifetime is defined by the adsorption of the inhibitor onto the reservoir rock, hence any chemical that interacts with the adsorption process will have an impact on the squeeze lifetime. This paper experimentally demonstrates potential changes to inhibitor adsorption from a polymer EOR project by demonstrating the complex interactions between HPAM and phosphonate scale inhibitors with respect to adsorption.
This work presents a detailed coreflooding programme, supplemented with bottle tests, to identify the impact of HPAM on a diethylenetriamine penta(methylene phosphonic acid) (DETPMP) squeeze lifetime. A range of pH values, representing the expected inhibitor injection pH, have been studied on consolidated and crushed Bentheimer sandstone. A temperature of 70°C is used throughout as it represents the likely maximum temperature at which HPAM would be applied and the typical temperature at which DETPMP would be used in squeeze applications.
The results presented show that scale inhibitor application pH is key in defining the impact of HPAM on DETPMP adsorption. Neutral pH displays a reduced squeeze lifetime, believed to be due to reduction of adsorption sites by HPAM. However, this impact could be countered by injecting this type of scale inhibitor at a low pH (e.g. pH 2). Static tests performed alongside the corefloods show that even low inhibitor concentrations (as found in SI pre-flushes) are sufficiently acidic to fully precipitate the HPAM from solution, but did not impact the adsorption.
This study suggests, contrary to the commonly held view in the industry that EOR polymers may negatively impact squeeze lifetime, that with the correct selection of inhibitor type and their application pH it is possible to achieve the same results as in a conventional reservoir.