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62 III.B. Techniques to Detect Hydrates.
When partial or complete blockages are observed in flowlines, questions always arise about the plug composition. Is the blockage composed of hydrates, paraffin, scale, sand, or some combination of these? Such questions are more easily answered with line access, as on a platform where a number of detection devices (e.g. thermocamera, gamma ray densitometers, or acoustic sensors) can be used as indicated in Section III.B.1.
Indications of the blockage composition are obtained through combinations of (1) separator contents and pig (sphere or ball) returns as direct indicators and (2) line pressure drop as an indirect indication. Separator contents and pig returns provide the best indication of pipeline contents and should be regularly inspected, even when blockages are not a problem. Separator discharges and the pig trap provide valuable information about line solids such as hydrates, wax, scale, sand, etc. and may be used as an early warning of future problems.
A less direct flow indicator is line pressure drop buildup, which differs for hydrates and for paraffins. Pressure drop increases are usually more noticeable than flow rates changes. With the exception of hydrate formation from gases without oil/condensate (with a typical pressure drop schematic in Figure 50a), hydrates usually cause a series of sharp spikes (Figure 50b) in pressure as hydrate masses form, agglomerate, and break, prior to final blockage. With paraffins the pressure buildup is more gradual, as deposition on the periphery of the pipe wall causes a gradual increase in line pressure drop. Pressure changes immediately before the blockage should be studied in addition to such things as fluid slugging, gas/oil ratio, water cut, reservoir pressure, and choke setting, all of which can affect the flow and pressure drop.
When blockages occur in wells it may be difficult to distinguish the cause. Frequently only heating or mechanical means are available to detect the plug source. In flowlines and in wells, solid blockages of scale, rust, sand, etc. are less readily detected and removed than hydrates or paraffins, so treatment for the more solid plugs should be considered as when hydrate and wax treatments fail.
In this section on detection of hydrate blockages, Section III.B.1 considers early warning signs of hydrates, and Section III.B.2 considers methods to determine the center and length of the plug. A significant amount of material in this section was obtained from DeepStar IIA Report A212-1, Paraffin and Hydrate Detection Systems, by Paragon Engineering and Southwest Research Institute (SwRI) (April 1996). Another major resource was the Statoil Hydrate Research/Remediation group, who contributed through in-depth interviews (July 13-15, 1997); this group has more field experience in hydrate remediation than any other at present, perhaps by an order of magnitude.
63 III.B.1. Early Warning Signs for Hydrates.
Unfortunately no indicator gives a single best warning of hydrate formation. Frequently the pressure drop in a line, commonly thought to provide the best warning, is wholly inadequate for reasons given in Section III.B.1.a. Instead a suite of indicators should be used to provide the best early warning before blockages occur.
Of the three portions of the offshore process where hydrates form blockages, early indicators of well formation are least developed. Hydrates in a well are most often announced by abrupt flow blockages, accompanied by a high pressure drop. In normal operation however, the well temperature is high enough to prevent hydrate formation. It is only during abnormal operations such as start-up, shut-in, testing, beginning gas lift, etc. that hydrate formation becomes a problem. When hydrates form without warning in a well, the engineer turns to Section III.C, “Techniques to Remove Hydrate Blockages.”
Early warning methods in the subsea pipeline (Section III.B.1.a) and platform (Section III.B.1.b) are discussed independently below. However, even with the methods listed in this section, there is a significant need for better hydrate detection.
III.B.1.a Early Warnings in Subsea Pipelines. There are four methods for warnings of hydrate formation in a subsea pipeline: (1) pigging returns, (2) changes in fluid rates and compositions at the platform separator, (3) pressure drop increases, and (4) acoustic detection. Each method is discussed in the following paragraphs.
(1) Pigging Returns. Periodically a flexible plastic ball or cylinder called a
“pig” is pressure driven through pipelines to clear them of condensed matter. The pig’s trip is initiated via a “pig launcher” and ended by a “pig catcher or receiver”, with the debris swept from the pipeline into a “pig trap”. A detailed DeepStar II CTR 640- 1, Pipeline/Flowline Pigging Strategies, by H.O. Mohr Research and Engineering, Inc. (August 1994) provides a tutorial of this technology.
Frequently hydrate particles are found in pig traps before hydrate blockages occur in pipelines, providing notice of the need for corrective action, e.g. increased methanol injection. For example hydrate particles may occur when they have been suspended in an oil or condensate with a natural surfactant, such as the Norsk Hydro oil shown in Figure 34 and accompanying discussion in Section II.G.2.a. Statoil’s Gullfaks subsea installation may have undergone several start-ups with hydrate present, but without problems (Urdahl, 1997) before a blockage in January 1996.
Rule-of-Thumb 17. A lack of hydrate blockages does not indicate a lack of hydrates. Frequently hydrates form but flow (e.g. in an oil with a natural surfactant present) and can be detected in pigging returns.
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Pigging returns should be carefully examined for evidence of hydrate particles. Hydrate masses are stable even at atmospheric pressure in a pig receiver or catcher discharge. The endothermic process of hydrate dissociation causes released water to form an ice shell, which provides a protective coating to inhibit rapid dissociation (Gudmundsson and Borrehaug, 1996).
However, it may be very expensive to provide pigging, either via a mobile pigging vessel over the well or from the well head without round-trip pigging capability. Such costs make examinations of pigging returns an infrequent luxury.
(2) Changes in Fluid Rates or Composition at Platform Separator. When
the water production rate is small it may be possible to monitor the rate of water production as an indication of hydrate formation. If the water arrival decreases appreciably at the separator, hydrates may be forming in the line.
_____________________________________________________________________ Case Study 9. Separator Water Rate as an Indicator of Hydrate Production.
In a controlled experiment, British Petroleum formed hydrates in a 14.5 inch I.D., 13.7 mile long gas line in the southern North Sea. Corrigan et al. (1996) reported that prior to the trial water arrived at the separator in the amount of 1.3 bbl/MMscf. The test was started at the time marked “Day 1” in Figure 51. After methanol injection was stopped, the separator water arrival stopped completely after about 30 hours (no increase in water volume), while gas flow rates remained steady and pressure drop did not change.
The first significant increase in line pressure drop (to 2.4 bar in Figure 52) was observed 46 hours after the start of the test. A further rise in ∆P to 3.3 bar was noted after 3 days. Seventy-four hours after the start of the trial, large fluctuations in the gas flow rate were observed that were concurrent with further increases in ∆P. A large slug of liquid, presumed hydrates, arrived at the slug catcher at the trial conclusion. BP estimated 50 metric tons of hydrate were formed before methanol injection was resumed.
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The above case study is evidence that separator water rate provides an early indication of hydrate formation in a gas line with almost no oil/condensate and little water production. When water production is substantially higher, it may be difficult to monitor changes in separator water arrival for an early warning (Todd, 1997; Austvik, 1997).
Statoil’s Gjertsen (1997) suggested that changes in gas composition provide an early indication of hydrate formation. In a rich gas field in the Norwegian sector of the North Sea, chromatograms showed a removal of hydrogen sulfide (H2S) from sour gases as hydrates form. Hydrates particularly denude H2S from natural gases, due to