The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above).
Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength.
The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
This paper reviews recent developments in the prediction of the likely future corrosion losses and of the maximum pit depth for steels exposed to marine environments. A robust mathematical model based on corrosion science principles and calibrated for immersion conditions to an extensive range of literature and new data is described. The model has provided explanations for the effects of steel composition, water velocity, depth of immersion and seawater salinity and also has facilitated new interpretations of data for long-term pitting corrosion. This paper briefly overviews these developments and refers to some typical applications, including marine corrosion of ship ballast tanks, corrosion of sheet piling in harbours and corrosion of offshore platform mooring chains.
Physical infrastructure plays a major role in the most modern societies. So-called whole-of-life assessments increasingly are being used for decision processes. Such algorithms require models of sufficient rigor and robustness to represent (a) the demands or loadings expected to be placed on the system; (b) the ways in which the system may respond; and (c) prediction of likely future response, including deterioration and effectiveness of repairs. Consistent with modern decision theory, the models required for (a) and (b) are probabilistic (Melchers, 1998). Until recently, models for (c) were largely ignored. Most infrastructure has expected lives of several decades. As argued previously (Melchers, 2005), the only way such predictions can be made is to invoke a combination of scientific understanding of deterioration processes and sound mathematical modeling. The present paper is concerned with the development of corrosion models, particularly for longer-term exposures. Despite good maintenance regimes, and the availability of protective coatings and of various forms of cathodic protection, field evidence shows that existing infrastructure often shows signs of corrosion, particularly in severe environments, such as for offshore facilities, along marine coastlines and in harbors.
Young Technology Showcase - No abstract available.
For more than 60 years, internal plastic coatings have been used for corrosion protection on tubing, casing, line pipe and drill pipe. One of the historic concerns with the use of internal plastic coating is the threat of mechanical damage and subsequent corrosion cell generation. Through the earlier years of usage of internal plastic coatings, applicators relied solely on enhanced surface preparation and adhesion to ensure minimal exposure of the steel substrate if damage were to occur. Even with this minimization, the potential for corrosion was still a concern for some. Due to this, a focus on developing internal coatings that offered higher degrees of abrasion resistance was initiated. At this time, several materials have been developed that offer abrasion resistances up to twenty times greater than what had previously been seen. These abrasion resistant materials allow internal coatings to be used in applications that were previously filled with alloys and GRE liners. These applications include: production/injection wells that rely on frequent mechanical intervention, rod pumping wells, completion string systems and environments containing high amounts of entrained solids. This paper outlines the development of these products including the different chemistries used and their abrasion resistance, impact, laboratory evaluation of their abrasion resistance and initial case histories of applications where internal coatings have historically been excluded.
Maintaining wellbore integrity throughout the life of a well has become a major concern for production optimization. Corrosion logs are mainly run to investigate and inspect the casing integrity and corrosion severity. In this paper, we will discuss a case study for well integrity monitoring for a specific case, where the focus of monitoring integrity was on a miscible CO2-EOR pilot to evaluate and understand the effect of miscible supercritical CO2 flood on the down-hole well equipment,the effect of CO2 on various designed materials, the Impacts of corrosion inhibitor on well metallurgy in a CO2 environment, Integration of differently data sourced in forecasting and therefore designing mitigation plans of zones that could be potentially negatively impacted, perforation design and optimizing for well performance, and down-hole completion accessories and logging portfolio selection.
The case study comprises three wells drilled vertically; a number of mechanical and electromagnetic wire-line logging tools were deployed to investigate the integrity of the wells.
Cement bond integrity was evaluated prior to injection of supercritical CO2 into the reservoir in order to ensure correct cement placement and protection was in place for adequate mechanical support for the casing, to safeguard against fluid corrosion, and to isolate permeable zones at different pressures to avoid hydraulic communication.
Another approach was targeted to better understand the area presumed to be affected early by the flood by assessing the open hole data conventional logging technologies to determine the permeability contrast of the reservoir in order to predict the CO2 flow path and entry points.
The paper will expound some important lessons learnt were derived from this case study and the critical data needed to provide understanding of the EOR flood behavior that can be used as indicators for mitigation plans and robust design of CO2 impacted wells.
ADCO initiated the CO2 EOR study during mid 2008 with the main objective being to develop a CO2 EOR portfolio based on detailed laboratory studies, simulation studies, and field pilot studies. The ADCO CO2 pilot project started with a company-wide screening study identifying both the most appropriate EOR option and most likely reservoir candidates. The pilot was originally planned to operate for one year, from November 2009 to November 2010. However, upon the completion of the approved project objectives in June 2010, a decision was taken to expand the project scope to evaluate the CO2 performance in the transition zones.
Gas injection is one of the most common methodologies for Enhanced Oil Recovery (EOR) in the oil and gas industry. One of the challenges associated with gas injection, e.g. natural gas, CO2 and N2, is potential asphaltenes precipitation and subsequent deposition causing blockage throughout the production system. It is crucial that precipitation of asphaltenes is identified early in the planning stage of any EOR project so that mitigation strategies are put in place to avoid negative impact on well performance.
A line-drive pattern CO2 pilot is planned in a super giant field A onshore Abu Dhabi and hence single phase bottomhole samples were collected from a nearby well to evaluate asphaltene stability under CO2 gas injection. This paper presents the results of the lab work that clearly indicate no asphaltene deposition problems during natural production; however, asphaltenes will precipitate when CO2 is mixed with the crude at mole fractions as low as 0.2. Based on the experimental results and on field results from another CO2 pilot in field B, which experienced asphaltene deposition problems, it was deemed necessary to include provisions for continuous downhole chemical injection of asphaltene inhibitors in the CO2 pilot producers for field A.
The challenge is to combine the requirements to prevent CO2 corrosion and to prevent asphaltene deposition in the well. The paper describes the different completion design options that can be used to achieve the desired target taking into account the cost impact. The designs incorporate combinations of different tubing materials and chemical injection options with pros and cons to using each, keeping in mind the reservoir monitoring requirements that can add more constraints to the completion design.
Polyolefins have a long and successful track record as a material for low pressure piping applications in Europe. For example, drainage systems made from Polypropylene Block Copolymers (PP-B) have now been in service for over 30 years and since the introduction of the new PP high Modulus (PP-HM) grades in the 1990's, market growth has been remarkably high. This market growth was further supported by the emergence of technology that allows for the production of large diameter PE/PP pipelines of up to 4 m in diameter.
Against this background, the polyolefin pipe market in Asia and Middle East is now set for a similar strong growth to that witnessed in Europe. With the continued failure of systems made from alternative materials such as concrete, there is a significant opportunity for polyolefin pipes to replace existing networks. This paper will underline the whole life value of polyolefin pipes compared to other systems, highlight the potential for large diameter plastic pipes and underline the growth and subsequent opportunities for plastic pipes in the Middle East, particularly in the petroleum industry.
The demand for polyolefin pipe systems experienced significant growth in Europe over the last 15 years. For example, polypropylene (PP) has seen a 1000 % increase in demand for sewage and drainage systems since the early 1990s, with further growth forecasted.
Today, the Middle East is set for a similar growth to that witnessed in Europe, with huge opportunities available for both pressure and gravity piping systems. Such opportunities are particularly noticeable in the Middle East oil and gas industry, where investment in petroleum and energy plants will generate significant requirements for pipes. In previous years, limited availability of specific polyolefin pipe grades in the region had hampered regional growth of this sector. However, following the start-up of the Borouge 2 petrochemical complex as shown in Figure 1, regional production of grades such as Polypropylene Block Co-polymer and High Stress Crack resistant PE 100 grades will be available to support the growth of the Middle East plastic pipe market.
Pipe repository - No abstract available.
The Canadian energy sector pioneered and developed industry-leading oil- and liquids-rich reservoir acidizing technology. This involved new acid additive chemistry and completion techniques. However, many of the newer technical professionals in the industry have not been exposed to this technology. The first section of this paper outlines acidizing technology, with a focus on application to current new opportunities.
Many of the current oil- and liquids-rich plays involve naturally fractured carbonate reservoirs. Acid treatments designed to enhance the conductivity of the existing fracture system can provide more-effective reservoir drainage than proppant fracturing treatments. The second section of this paper discusses how new placement techniques can offer more-effective zonal isolation while reducing completion time and associated costs, and how acid pre-pads can also reduce breakdown pressures and help minimize near-wellbore (NWB) tortuosity effects in many shale and sandstone reservoirs.
Lessons from The Past
Acid Blend Design Considerations
1. Acid types and applications.
2. Iron-induced sludging and additive dispersibility.
3. Non-emulsifiers/antisludging agents.
4. Testing procedures.
5. Iron-sulfide precipitation.
6. Corrosion of metals.
7. Corrosion inhibitors.
8. Sulfide stress cracking (SSC).
10. Wetting agents.
12. Fines migration.
13. Paraffin and asphaltene precipitation.
14. Scale precipitation.
15. Additional additives.
Nowadays, as the deep gas reservoirs in Daqing are explored, the complex volcanic reservoirs have been the major reservoirs in deep natural gas exploration and production. The reserves of volcanic gas reservoirs take up 88% of the total gas reserves. However, the deep complex gas reservoirs may cause heavy pollution during the drilling completion, and some of the barriers between target zones of the wells are very thin, leading to a poor stability. Additionally, because of the complex water/gas relations in the formation, such as appearance of bottom water and water and gas sharing the same formation in some wells, the fracturing operations will induce water channeling. All these facts may cause the failure of the fracturing operations.
Especially, when the fractured formation is close to the water/gas interface, the fractures will easily extend into the water layer. The existence of water in the gas wells directly leads to the reduction of production and recovery rate of the gas reservoirs, or even kills the gas reservoir in the worst cases. For these types of gas wells, acidization technology is a promising solution. It not only avoids the pollution near the wells of volcanic formation, but also chemically dissolves the fillings in the fractures and pores, improves formation seepage flow environment, increases fluid mobility, and finally optimizes the productivity. Acidization technology also has the advantages of low investment and quick payback.
This paper reports the volcanic reservoir acidization technology we developed. The lab test results show that this technology solves the problems of high erosion rate of the oil strings under high temperatures (125-160 degree of Celsius). The acidization technology is applied in three wells, and the productivity of those increases profoundly.