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Abstract Tracking the bending and internal pressure history of coiled tubing (CT) at the reel and guide arch, as it is run in and out of wells during field operations, is accepted throughout the industry as the preferred method for predicting the fatigue damage distribution along the string throughout its life. A mathematical model, relating bending strain and hoop stress (from internal pressure) to cumulative fatigue damage can be applied to this recorded field loading history. Such models determine when tubing should be retired or when tubing cuts should be made in order to maximize the utilization of the pipe while minimizing the chance of pipe failure. The problem of CT fatigue has been studied extensively in the lab, using constant pressure bend cycling and/or axial coupon testing. However, models resulting from experimental programs have seldom been correlated in the literature with CT behavior under field loading conditions. This paper presents such validation by correlating the experimentally determined cycles to failure of CT samples which have had extensive use in field operations, to predictions from an advanced predictive fatigue algorithm. The string, from which the samples were taken, had been removed from service based on criteria specified by the operating company for which the CT work was being performed. This stated that strings were to be retired after a given value of "running meters" had been reached, rather than on the actual bending and internal pressure history. Excellent agreement is demonstrated between the actual remaining fatigue life of the tubing, determined experimentally, and the estimated cycles to failure predicted by the fatigue model. Therefore, it is shown that the string could have been safely utilized much longer than the current string retirement specification allows. Based on the results of this testing, the operating company has changed its criterion for CT string retirement to one that relies on tracking of bending and internal pressure history and subsequent predictive fatigue modeling based on this history. Introduction As the performance envelope for CT well service continues to expand, the importance of being able to accurately predict fatigue damage to the pipe, induced by the tremendous bending strain the pipe is subjected to, becomes increasingly important. Fatigue damage is the primary factor used to determine when a CT string should be retired from service. There are essentially no other applications where steel alloys are subjected to cyclic loading at such high strain values. Thus, the development of mathematical models used to specifically predict fatigue damage under the conditions encountered in field operations has taken place only in the last 10 to 12 years, making it a relatively new field of study. A considerable amount of laboratory-scale testing, and full-scale testing under controlled conditions, have been conducted in conjunction with the development of existing predictive fatigue models. However, there has been very little correlation between the data generated by these fatigue models and the actual fatigue damage observed in pipe that has seen extensive use in field operations. Lack of such validation still leads some service companies and operating companies to base CT string retirement criteria on the concept of "running feet/meters". This is defined as the distance traveled by the pipe as it is run off the reel and over the guide arch, typically measured in one direction only. In other words, a single trip in and out of a 10,000 ft well would be interpreted as 10,000 running feet. While this concept does give a measure of the utilization of the CT, it ignores the effects of internal pressure, the effects of localized repetitive cycling (which can lead to untracked fatigue "spikes"), variations in wall thickness of tapered strings, and the severity of the bending strain the CT has been subjected to.
Abstract Coiled tubing (CT) monitoring tools are being utilized on a larger percentage of field jobs now as compared to the past. They are being used on both CT intervention and CT drilling operations. The objective of this paper is to demonstrate how a wall thickness measurement device can enhance and improve the calculations made by a CT fatigue algorithm. Experimental work was done which shows how the wall thickness can vary depending on the pump rates, the fluid being pumped and the amount of tubing that is spooled on the reel. Reference four provides detailed information related to wall reduction in CT during pumping operations. Typically, fatigue models will utilize an estimated, nominal or minimal wall thickness to perform the fatigue calculations. The amount of wall reduction in CT can vary greatly and as a CT string acquires fatigue, there is a chance that the estimated wall thickness may not reflect the actual wall thickness of the pipe. Recent modifications to fatigue tracking software allow the user to incorporate the real-time (or recorded) measured wall thickness into the fatigue calculations. This paper will discuss the experimental work, the modifications to the model, and case histories in which the wall thickness measurement device was used. Calculating the CT fatigue using the measured wall thickness will increase the accuracy of the CT fatigue profile. This will allow CT service companies to operate at an increased efficiency. Operating companies will also benefit from this technology because there will be fewer fatigue failures at the well site due to the increased accuracy in the fatigue calculations.
Abstract An assisted history matching method has been developed where simulations are quantitatively compared to observed 4D seismic and production data and then updated in an objective manner. The approach uses experimental design to initialise a stochastic parameter search but also to derive a proxy model of the misfit between observations and predictions. The proxy model is then used to guide the stochastic search algorithm to speed up convergence. Updating of the proxy model periodically during the search improves convergence further. The approach was applied to the Schiehallion UKCS field where we use 6 years of production along with six 4D seismic surveys. The proxy model, a quadratic regression equation, was derived for the combined misfit of both production and seismic data. Transmissibility of a number of barriers and faults as well as permeability and net:gross (NTG) were modified to improve the history match. The approach improves the efficiency of finding the best models. Experimental design reduces the number of models to initialise the stochastic approach by a factor of 10. Continuous updating of the proxy not only leads to three times faster convergence but also enables better models to be found. History matching without experimental design or proxy derived gradients reduced the production misfit by sixty six percent while our new method gained a further ten percent reduction. We improved the exploitation of misfit information without compromising exploration of the parameters. History matching is a very important activity during the development and management of petroleum reservoirs. Obtaining matched models is fundamental to ensure reliable future forecasts, and give an improved understanding of the geological description and the dynamic behaviour. Improved recovery factors can then be achieved by accurately locating infill wells and maintaining production longer.
- Europe > United Kingdom (1.00)
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- Research Report (1.00)
- Overview > Innovation (0.35)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Europe > United Kingdom > UKCS Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 17 > Girassol Field (0.99)
Introduction The inefficiency of batch treatment down the annulus to prevent corrosion in gas-lift wells led to a search for a better method. Squeezing inhibitor into the formation was attempted and appeared to be an improvement over other methods of treatment. With these other methods it was difficult to get the chemical where it was needed because a high fluid leg would cause a major portion of the chemical to enter the tubing string at the working valve, which was too high to give complete protection. A low fluid leg would cause the chemical to dehydrate and leave a gummy substance on the outside of the tubing and on the inside of the casing. This tendency could be partially overcome by using large amounts of diluent (5 to 10 bbl) with the chemical, but such treatment was time-consuming and expensive. Sticks and pellets were tried with poor results. Theory of Squeeze It was found that some inhibitors would adsorb to sand rapidly and would desorb slowly. Laboratory work indicated that this adsorption-desorption rate was sufficient to warrant field testing. The high chemical concentration (11,000 to 1 million ppm) in contact with the steel during the squeeze is also a factor. Limited field tests to evaluate these two factors have been performed, but are inconclusive. Squeeze Treatment Since Nov. 1954, 60 wells have been squeeze-treated with a total of 160 squeezes. These 60 wells are located in 10 different fields and produce from 19 separate reservoirs. They vary in depth from 3,000 to 12,000 ft. Of the 60 wells, four are natural flowing wells, 47 are gas-lift wells, eight are gas condensate wells, and one is a pumping well. From the information available, it appears that about 150 wells have received this inhibitor squeeze-type treatment. Approximately 350 separate squeeze treatments have been done in these 150 wells. A breakdown of these 150 wells as to method of production is as follows: gas-lift, 85; natural flow, 15; pumping, 20; and gas condensate, 30. Production from these wells, located in Texas, Louisiana and Arkansas, is both sweet and sour. Some are producing from sand and some from lime-stone formations.
Abstract An intuitive, trial-and-error approach to history-matching can be costly and time-consuming. In an attempt to reduce these factors, considerable efforts have been made to automate history-matching procedure for implementation on high-speed computers; and several methods based on ex post facto techniques have been developed for this purpose. This study examines presently available automatic history-matching algorithms reported; discusses the viability of each; and explores the fundamental weaknesses of two of the more promising methods. In addition, the existence of alternative approaches to solving the inverse problem for analogous, but less complex, situations is noted. Most published methods address the problem of single phase flow, although many would appear to be satisfactory for multiphase flow. The most serious problem encountered in automatic history-matching is the tendency to construct ill-conditioned systems of equations Ax=b. By the very nature of the history-matching problem, inherent uncertainties exist in both A and b, because they are based on a measured performance history. This history-matching problem can therefore be treated only by incorporating some a priori information about the solution vector x. But due to the scarcity of physical data, even this requirement cannot be adequately satisfied. It would seem that the current automatic history-matching methods are less than satisfactory. Such methods are simply not competitive with manual techniques which an experienced reservoir engineer might employ. It would appear, then, that the determination of effective and reliable solutions to the inverse problem requires development of improved methods of geological parameters, and adaptation of mathematical techniques to allow for a more theoretical treatment.