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.
Stanitzek, Theo (AkzoNobel) | De Wolf, Corine (AkzoNobel) | Gerdes, Steffan (Fangmann Energy Services) | Lummer, Nils R. (Fangmann Energy Services) | Nasr-El-Din, Hisham A. (Texas A&M University) | Alex, Alan K. (AkzoNobel)
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Offshore pipelines are a viable option for the safe transport ofhydrocarbons in the Arctic. For continued safe and cost efficient operation, itis important to ensure integrity as well as minimize field inspection andintervention. This can be achieved through an optimized Inspection andMaintenance (IM) program. Determining the required frequency of IM, in a costefficient manner is critical for ensuring integrity and optimizing inspectionand maintenance costs without compromising safety. For piggable lines, smartpigs are used for In-Line Inspection (ILI). A conservative approach (small IMintervals) can be costly, increases the human / Remotely Operated Vehicle (ROV)exposure and yield little new information. A strategy with too little IM canlead to unexpected failures, as too little information is acquired on thecondition of the pipeline. An optimal IM strategy based on the condition ofpipeline is developed in this paper.
In this paper, major Arctic offshore pipeline integrity challenges areevaluated. Considering these challenges, a Risk Based Integrity Modeling (RBIM)framework has been proposed. Design challenges from the effects of ice gouging,strudel scour, frost heave, permafrost thaw settlement, and upheaval bucklingcan be mitigated through proper trenching and burial, as well as conditionmonitoring during operation. The major integrity challenges during operationmay arise from the progressive structural deterioration processes and changesin the right-of-way seabed conditions. The structural deterioration processeswill include time-dependent processes such as corrosion, cracking, andpermafrost thaw settlement. Non-time dependent (random) processes, such asthird party damage, ice gouging, strudel scour, and upheaval buckling will poseadditional risk during operation, but are not addressed in this paper. Theseeffects can be partially addressed through ILI and periodic seabed surveyinspections.
The risk to an Arctic offshore pipeline will be evaluated with respect tothe deterioration processes. The risk is estimated as a combination of theprobability of failure and its consequences. The probability of failure isestimated using the Bayesian analysis. Modeling the structural degradationprocesses using Bayesian analysis is not a new concept; however, modelingdegradation processes using non-conjugate pairs is a new technique that isdiscussed in this paper. Bayesian analysis is based on the estimation of prior,likelihood, and posterior probabilities. Field ILI data is used in theanalysis. The posterior models possess better predictive capabilities of futurefailures. The consequences are estimated in terms of the cost of failure andthe planned IM program. Cost of failure includes the cost of lost product, costof shutdown, cost of spill cleanup, cost of environmental damage and liability.Cost of IM includes the cost to access the pipeline, gauge defects, and carryout inspection and necessary minimal maintenance. Implementation of theproposed RBIM will improve pipeline integrity, increase safety, reducepotential shutdowns, and reduce operational costs.
Young Technology Showcase - No abstract available.
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.
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.
When they are located subsea, damaged pipelines are very challenging to repair. The extreme conditions, the risks related to pollution and the high daily rates of intervention vessels make the repair decision difficult.
Recently, composite repair solutions, originally developed for onshore use, where adapted for subsea application and tested, so as to get alternative solutions to apply when classical repair methods are not suitable or too costly.
Composite repair solutions for restoring the structural integrity of damaged pipeline have been available for some time. A modified version was specifically designed for subsea pipeline repair, using a dedicated resin applicable under water.
The repair system is designed to be installed by divers with a semi-automatic installation process: using pre-impregnated tape with a specific tool applying constant tension and winding path. This tool is now being adapted for ROV use, to allow performing deepwater repairs.
Several test campaigns, both in swimming pools and subsea were performed in Monaco, Abu Dhabi and in China for various oil operators, with a rigorous test protocol, supervised by a third party.
A finite element model of the composite repair allows calculating the number of layers, pattern and extent over the defect, in relation to the stress level in the pipe. This FE model was also validated through numerous burst tests, confirming the reliability of the calculations.
The subsequent pressure test results indicated that the pipeline integrity was fully restored for damages such as metal loss and through thickness defects.
This composite repair system is designed to restore fully the structural integrity and pressure resistance of the pipeline for subsea application. It represents a cost efficient alternative to classical repair methods involving clamps, mechanical connectors or others.
During the last decade, DuPont has been developing an engineered fluoropolymer based internal downhole coating system, for downhole production tubes. This development work came as a response to critical needs expressed by major oil and gas producers in Europe, the Middle East and Northern / Latin America, in order to have a polymeric based coating solution that could be applied internally in downhole production tubes for the purpose of :
The ultimate objective of this exercise is to offer the oil and gas industry a reliable and sustainable static solution that would not require costly intervention for wells clean-up and maintenance and also to reduce the number of workovers required on oil and gas well producers, which would ensure lower production cost.
In order to develop such a new polymeric solution, a new approach versus the resin matrix design had to be used. The new coating system has an effective combination of a very low finished surface energy coupled with an improved pressure / temperature design envelope. Given the inherent design envelope limitations of current coating systems used by the old and gas industry, fluoropolymers were selected in order to develop such a new internal downhole coating system.
The high thermal stability and high flexibility of fluoropolymer-based materials provide a significant advantage in terms of mechanical properties retention in high pressure and high temperature environments, which is a must for an effective internal corrosion control. On the other hand, it has the lowest sticking tendency versus difficult type of organic and inorganic depositions, such as asphaltene and BaSO4, which provides an opportunity for a new cost effective approach in terms of maintaining oil and gas producing wells prone to such problems.
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.
As ADCO's oil fields mature, produced water increases. ADCO forecasts that the produced water may increase in the next 25 years as much as 10 fold (in excess of 600,000 BWPD by 2020 and more than 1,000,000 BWPD by 2027). On the other
hand, in order to support the reservoir pressure, ADCO is sourcing brackish water from deep aquifers (D, S and U). The produced water is then disposed back into aquifer S. This practice has high financial and environmental costs:
In order to strategically manage increasing volumes of produced water as the main oil producing reservoirs reach maturity, ADCO started pilots to re-inject untreated produced water in three fields in early 2000: Field 1 in 2002, Field 2 in 2010 and
Field 2 in 2003.
Positive pilot results in Field 1 led to field wide expansion of the Produced Water Re-Injection (PWRI) into one the oil bearing reservoirs and it was included in the Full Field Development Plan (FFDP). A pilot for re-injecting untreated PWRI is currently running in Field 2 for the past 16 months at a rate of more than 20,000 bwpd. Positive outcome so far led to raising funds to extend PWRI network to achieve re-injection rates of 50,000 BWPD into one of the oil bearing reservoirs in this field.
The pilot for Field 3 was plagued with interruptions since the start caused by PWRI system material integrity issues which did not allow concluding so far whether untreated PWRI re-injection into one of the oil bearing formations is achievable. In
order to address this situation, corrosion mitigation measures both for relevant surface facilities and downhole completions are being implemented and in parallel, an integrated coreflood testing/geomechanical properties study is on-going to assess the degree of treatment required to allow re-injecting produced water cost effectively in the most permeable oil bearing reservoir in this field.
ADCO's approach to managing increased produced water rates through pilots and learning from rock matrices testing/studies shows that managing field wide PWRI systems in a cost effective and environment friendly manner is achievable if planned sufficiently in advance and executed properly.