Article pubs.acs.org/EF
Production of Waxy Oils on the Norwegian Continental Shelf: Experiences, Challenges, and Practices Hans Petter Rønningsen* Statoil ASA, 4035 Stavanger, Norway ABSTRACT: This paper gives an overview of some important experiences and challenges with the production of waxy oils on the Norwegian continental shelf with regard to the control of wax deposition and gelling. Fundamental as well as operational aspects of wax and gelling control are addressed, such as (i) pipelines with severe wax buildup, (ii) prediction of wax deposition potential, (iii) measurement and monitoring of wax deposition in pipelines, (iv) pig design for efficient wax removal and criteria for determining wax pigging frequency, (v) wax pigging in gas-dominated flow lines, (vi) production of waxy, high-pour-point oils, (vii) production of waxy fluids from low-temperature reservoirs, and (viii) long-distance oil satellite tiebacks. In addition to relevant experiences and current status and trends, views on focus areas and directions forward are given.
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production of waxy fluids from low-temperature reservoirs, and (viii) long-distance oil satellite tiebacks.
INTRODUCTION The Norwegian continental shelf has an extensive transport infrastructure consisting of more than 8500 km subsea export pipelines (of which nearly 1000 km are oil export pipelines) and more than 3000 km subsea infield flow lines, mainly carrying multiphase mixtures of oil, gas, and water. A substantial fraction of produced fluids are oils and gas condensates containing paraffin waxes. These paraffins typically start to crystallize at temperatures in the range of 20−40 °C.1,2 With relatively constant ambient sea bed temperatures in the range of 4−8 °C, wax control becomes a key flow assurance challenge in most field developments, which has to be taken into account in design and operation. For infield production systems, the main strategy most often adopted is to maintain temperatures above the onset of wax crystallization by properly insulated flow lines. For multiphase systems containing water, the insulation has a dual purpose by preventing wax formation as well as gas hydrate formation. For hydrate control, an extra margin to allow for a certain cooling time during shutdowns is normally added. The extra “hydrate margin” is, of course, a benefit from a wax control point of view as well, although a certain wax crystallization in flow lines during shutdowns is not considered to be a problem as long as the oil does not gel. For various reasons, there are cases where it is impossible or at least would be extremely costly to avoid wax formation (because of distance, low flow rates in late life, or very low reservoir temperatures). Wax deposition will then occur in some parts of the production or transport system, and regular wax control has to be planned. In the sections below, various examples of production and transport systems where wax deposition or gelling may occur and how it is handled or planned are given. These cases are divided into certain categories of wax control challenges: (i) pipelines with severe wax accumulation, (ii) prediction of wax deposition potential, (iii) measurement and monitoring of wax deposition in pipelines, (iv) pig design for efficient wax removal and criteria for wax pigging frequency, (v) wax deposition and pigging in gas-dominated multiphase flow lines, (vi) production of waxy, high-pour-point oils, (vii) © 2012 American Chemical Society
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PIPELINES WITH SEVERE WAX ACCUMULATION Ordinary bypass pigs, as discussed below, have limitations with regard to wax thickness that can be handled safely without great risk of stuck pigs. In pipelines with severe wax buildup, i.e., wax thickness in the centimeter range and volumes of tens or even hundreds of m3, carefully planned and often time-consuming wax-cleaning campaigns, using specially designed equipment, have to be applied. Two field cases from the North Sea with severe wax accumulations illustrate that wax-cleaning operations for lines with severe wax buildup may be very timeconsuming and costly and provide some very important lessons. The first case is the 118 km, 8 in. inner diameter, uninsulated condensate export pipeline between the Heimdal and Brae A platforms. One became aware of wax buildup in this line in 2003 by observing a significant increase of pressure drop, as shown in Figure 1. This was related to the startup of a new gas
Figure 1. Pressure drop development in the Heimdal−Brae pipeline. Special Issue: Upstream Engineering and Flow Assurance (UEFA) Received: February 17, 2012 Revised: May 8, 2012 Published: May 18, 2012 4124
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condensate field in 2002, being tied back to Heimdal, where it is stabilized and exported together with several other light, waxfree condensates. The new export mixture had a wax appearance temperature (WAT) above the sea bed temperature and started to precipitate and deposit wax rapidly because of the high-temperature gradient at the wall. When pressure pulse monitoring was conducted in 2005, a wax profile extending from about 4 to about 50 km was found, in good agreement with the simulated temperature profile of the uninsulated line. A maximum wax buildup of about 20 mm and a total deposit volume of about 200 m3 strongly reduced the capacity of the line. There was an urgent need to get the wax deposition under control and ultimately clean the pipeline. A large number of undersized bypass foam pigs were run in the period from 2004 to 2009. A turbulent drag reducer was successfully used to maintain acceptable capacity, and the wax-containing field has been shut down for long periods to minimize further wax buildup. Although generally successful, in two cases, the foam pig got stuck and had to be pumped back to Heimdal with water from Brae A. Typically, 30−40 m3 of wax was collected in these operations. In 2008, an extensive “fill and soak” wax dissolver operation was conducted, however, with limited success. It turned out that wax dissolvers that worked quite well in lab tests had a marginal effect in the field. Figure 2 shows the
The other somewhat similar case, although much shorter and larger diameter, is the 37 km, 18.75 in. inner diameter North Sea pipeline between the Valhall and Ekofisk fields, which has been described by Marshall.3 In this uninsulated line, severe wax deposits had built up over years, and also, in this case, a maximum deposit thickness of about 20 mm was estimated. Huge amounts of wax deposit were removed by an extensive pigging campaign, starting with soft, flexible pigs, followed by a long series of gradually more aggressive pigs. The main lessons from this case were that potentially high risk could be managed by such a progressive approach and that bypass pigs greatly reduce the risk of blockage and stuck pigs.
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PREDICTION OF WAX DEPOSITION POTENTIAL Dealing with problems related to paraffins in crude oils has been a topic in the scientific literature for nearly a century. Vast amounts of experimental studies and modeling approaches have been published over the years. Rosvold4 and Aiyejina et al.5 have recently provided good overviews and comparisons of published wax deposition models. Wax deposition on solid surfaces is an extremely complex process, where fluid chemistry and thermodynamics, kinetics, and flow dynamics are closely linked together. Despite the complexity of the process, most attempts to model the rate of wax buildup on surfaces, such as pipe walls, have been based on a simple transport equation or diffusion law. It is fairly wellestablished that molecular diffusion, driven by a temperature difference between the WAT and the pipe wall, is an important factor controlling the amount of wax molecules available for deposition on a surface.6 It was realized very early7 that no deposit is formed even with wall and bulk temperatures far below WAT when there is no temperature difference. Numerous studies have confirmed this since then, and the more detailed effects of the temperature gradient were nicely demonstrated decades ago.8,9 However, there seems to be increasing evidence that wax deposition models that only consider wax buildup on a pipe wall resulting from molecular diffusion are, in general, inadequate.10 Without a physical mechanism for wax buildup being incorporated, this is actually not very surprising. In addition, although determination of WAT is quite well-established, there has been limited focus on the wax solubility curve (percent wax versus temperature), which is very important because the derivative of this curve goes directly into the diffusion equation together with the radial temperature gradient. Hoffmann and Amundsen6 showed a striking correlation between shapes of wax solubility curves and actual wax deposition in a model pipeline for a North Sea condensate, indicating that effort probably should be put into more accurate determination of the solubility curve. Lee11 did a detailed study of the heat- and mass-transfer processes taking place in the boundary layer and their coupling to wax formation and deposition and also discussed the importance of the shape of the solubility curve on the wax thickness profile along a pipeline. As further discussed in that study, the work performed at the University of Michigan, since originally published by Singh et al.,12,13 clearly indicates that formation of a gel layer contributes to the overall deposit, which is also the conclusion in a recent Statoil study.10 Aging of the deposit layer is found to be a consequence of a counterdiffusion process taking place in the gel. A recent in-house study of wax deposition in stratified two-phase oil−water flow has shown that gelation is significant at low shear stress and decreases with increasing shear stress.10 However, it is still somewhat unclear under which circum-
Figure 2. Wax thickness distribution in Heimdal−Brae derived from pressure pulse measurement.
wax distribution as measured in September 2011. It was concluded that the line would have to be cleaned by some kind of aggressive pig operation. Downstream concerns regarding receival of removed wax has thus far limited the options available, e.g., use of a high-friction jetting pig. One attempt to use a novel pig design, a slow-moving so-called hydraulically activated power pig, recently failed because of a technical problem. The pig had to be pushed back from about 8 km. It has thus far not been possible to clean the line, and evaluation of the way forward is ongoing. Fortunately, in this case, it has been possible to maintain acceptable capacity despite the wax accumulation, and a backup export route has been established for the waxy condensate. One main lesson from this case is that consequences of changed operating conditions, such as a new fluid composition, have to be carefully evaluated and wax control philosophy has to be updated accordingly. Besides, continuous monitoring and surveillance of pipelines by proper means are very important to avoid wax buildup that makes ordinary pigging impossible (especially important for uninsulated lines, where deposition occurs rapidly). 4125
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stances such gel layers form and become significant, especially in turbulent flow. Whatever mechanism of deposition, there will be a balance between buildup of a deposit layer and erosion by the shear action of the flowing fluids. Nevertheless, no model based on first principles is available; hence, shear effects are normally accounted for in an empirical way with tuning parameters, if accounted for at all. Finally, there are important effects of water present in multiphase systems, which are still not well-understood and taken into account, again especially in turbulent flow. In stratified flow, wax deposition occurs mainly on the oil-wetted wall area.10 The wax buildup data from the Heimdal−Brae pipeline discussed above, in terms of both pressure drop and pressure pulse/tracer measurements, can be reproduced using the OLGA RRR wax deposition model,14 with various combinations of adjustable parameters, i.e., roughness factor (which multiplied with local wax thickness gives local roughness), diffusion coefficient multiplier (correction of the default Hayduk−Minhas coefficient15), and shear stripping parameters (in the Matzain shear stripping model16), as shown in Figure 3.
Figure 4. Inlet pressure development (from February 3 to March 4) in Heimdal−Brae based on the OLGA RRR wax model.
Figure 5. Wax thickness development and temperature profile for Heimdal−Brae simulated with the OLGA RRR wax model. WAT is from PVTsim. Figure 3. Wax deposition profiles in Heimdal−Brae simulated with the OLGA RRR model with different combinations of adjustable parameters (diffusion coefficient multiplier, roughness factor, and shear stripping).
experimental determination of the rate of wax deposition at realistic conditions in small scale and scale-up to large pipelines,6 (iii) experimental investigations of wax deposition in two-phase oil−water flow,10 and (iv) further exploring the “gel layer” approach of the University of Michigan and its relevance in wax deposition modeling together with the diffusion approach of the OLGA wax deposition model. The wax deposition modeling is important as part of an “expert decision tool box”, together with (i) knowledge and understanding of chemistry and physical phenomena, (ii) key experimental data (solubility and deposition), (iii) flow modeling, and (iv) experience from analogue fields. Put together, this will give the necessary basis for developing a robust wax control philosophy for a given field development.
In all cases, an oil content of 60% in the deposit has been assumed (on the basis of samples from back flow of a stuck foam pig). The problem with modeling without knowing the answer is to decide which parameter combination to use, but careful deposition experiments might give some indication of diffusion coefficient, deposit oil content, and shear stripping. It is further shown in Figure 4 how a diffusion coefficient multiplier of 6, roughness factor 0.5, and no shear stripping give reasonable agreement with observed inlet pressure development. Analysis of pressure pulse measurements have later indicated that local roughness is more equal to local wax thickness, with an upper limit of about 7 mm. Observations from the Valhall pipe cleaning3 indicated even higher roughness. Figure 5 shows the progressive wax buildup together with temperature profile and WAT. The measured wax distribution in Figure 2 shows some more deposit beyond about 40 km. This is most likely because various attempts to clean the line has mobilized some of the deposit and caused a certain redistribution. Concerning the way forward, we have decided on some focus areas for improved capability to assess wax deposition in new transport lines: (i) improved experimental methodology for determining the wax solubility curve of real fluids, (ii)
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MEASUREMENT AND MONITORING OF WAX DEPOSITION IN PIPELINES Pressure pulse technology17 has been successfully applied numerous times by Statoil in the condensate export pipeline between the Heimdal and Brae A platforms, mentioned above. This method has been a very important tool in the planning of wax removal actions for this pipeline, in monitoring of the effects of the actions as well as for regular condition surveillance. The method was originally mainly applied for well and pipe flow measurement but soon found application for pipeline inspection in general and solid detection in particular.18 In short, the method is based on creating a water hammer type of pressure pulse in the pipeline by quickly 4126
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Figure 6. Wax distribution in Heimdal−Brae from pressure pulse at three times. The March 7 curve illustrates the effect of a stuck foam pig being pushed back, thereby removing wax.
be taken when using it for short lines. Because of the short response times, very fast acting valves are needed. In one case with a 3.4 km pipeline, where the method was used to locate a lost pig module, it later turned out that the location indicated by the pressure pulse was about 3 km off. Besides, the method is not considered qualified for multiphase pipelines. Distributed temperature sensing using fiberoptic technology has been widely applied for a long time for wellbore temperature profile monitoring as well as failure monitoring of electric cables in several of Statoil’s North Sea direct electrical heating (DEH) systems. There may be a potential for transforming the temperature information on the outer steel wall (underneath insulation) into a measure of wax deposit thickness on the inside of the fluid-carrying pipe. This use of the technology is currently explored as a possibility for real-time monitoring of the risers for Statoil’s new low-temperature field developments in the Barents Sea (see below). In Petrobras’ Papa Terra field development offshore Brazil, fiberoptic cables for temperature monitoring are included in integrated production bundles (IPBs) with electrical heating.20 Hoffmann et al.21 have described a new technology for continuous monitoring of wax deposition in subsea pipelines, which has been successfully tested in laboratory scale. The method is basically based on the same technique as the heatpulse wax removal method.22 The principle is to apply a short external heat pulse to the pipe wall and measure the thermal response, which is governed by the thickness and thermal properties of the insulating wax on the inside. This technology may be useful in combination with a DEH system for heatpulse wax removal, e.g., in cold flow systems where monitoring of wax deposition will be very important (see below).
closing a valve. The pulse can be created at either the inlet or the outlet. Normally, an existing topside valve is used to generate the pulse. The only modification required is typically to install a proper pressure transmitter. The pressure pulse travels at the speed of sound through the pipeline and halts the fluid on its way, continuously converting friction and kinetic energy into static pressure. The pressure response recorded by a pressure transmitter downstream of the inlet valve (or upstream of the outlet valve) is analyzed and provides a footprint of the fluid and flow conditions at the pulse front. When the speed of sound is measured (correlating two pressure transmitters) and an acoustic velocity model is used together with assumptions about wall roughness, the internal diameter variation along the pipeline and, hence, the deposit thickness distribution are calculated from the pressure versus time response. The pressure pulse service provided by Markland (Norway) has been used more than 10 times in the period from 2005 to 2011 for monitoring the state of the Heimdal−Brae pipeline. Measurements from both sides have been applied to cover the whole pipeline length of 116 km. Figure 2 shows a typical deposition profile as measured in January 2011. Although there are uncertainties, e.g., in the wax layer roughness assumption, the method at least provides a good order of magnitude estimate and a very good relative measure of the time development. To increase confidence, tracer measurements19 have been used to quantify the free pipeline volume. With knowledge of the original volume, the total volume of the deposit is calculated. The roughness has been used as a tuning parameter in the pressure pulse model to obtain the deposit thickness distribution shown. As mentioned above, a roughness equal to local wax thickness but limited to 7 mm has been found as adequate. Figure 6 illustrates how it has been possible to monitor the effect of various actions. A significant erosion of the peak accumulation is seen after a stuck foam pig had to be returned to Heimdal. Although applied successfully for a long, single-phase pipeline, the method has some limitations; e.g., care has to
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PIG DESIGN FOR EFFICIENT WAX REMOVAL AND CRITERIA FOR WAX PIGGING FREQUENCY Pigging is widely used for dewaxing of North Sea oil pipelines, sometimes in combination with chemicals. Because of both operational cost and environmental concerns, there is a wish to reduce chemical usage and have pigging as the main wax 4127
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Figure 7. Illustration of the continuity principle applied to dewaxing bypass pigs.25
example is the 80 km, 16 in. export pipeline from the Troll C platform to the onshore Mongstad terminal. This was first extended with a Y-branch from the Kvitebjørn field and later with another branch from the Gjøa field. Because of a limitation of only one pig in the system at any time, primarily because of the risk for collision or interference between pigs in the Yconnections, this made it necessary to do very careful evaluations of wax buildup and associated pigging frequency from each field. The conclusion was that it would be possible, with three nodes in the system, to avoid multiple simultaneous pigs. However, when a fourth branch was considered, this could no longer be guaranteed with current practice and pigging criteria. Hence, much more detailed operational pigging procedures for controlling launch times and pig speed, combined with new technology for pig tracking and monitoring, would be necessary. Qualification of such a system is currently being considered. With better and possibly less conservative criteria for wax pigging frequency, such qualification might not be required. Although there is limited documentation, it seems like the great majority of stuck pig incidents worldwide, related to wax pigging, is in systems with non-bypass pigs. The reason is, of course, that the frictional force between the wall or deposit layer and the wax plug in front of non-bypass pigs easily becomes very high.23 In one case from a Statoil-operated North Sea pipeline, a pig without bypass accumulated in the order of 3 m3 of solid wax on its way through the 43 km, 15 in. inner diameter pipeline and nearly got stuck in the riser.24 As a result of this incident, a new pig design with flow through the pig body as well as jetting toward the pipe wall ahead of the pig was implemented. Bypass pigs have become more or less standard in Statoil’s wax-cleaning operations in the North Sea. An overview of principles and design issues of bypass pigs has been provided by O’Donoghue.25 Figure 7 shows a principle sketch of a bypass pig used for wax removal. Bypass, meaning that a certain fraction of the total driving flow passes through the pig body and causes a jetting action ahead of the pig, greatly reduces the risk of stuck pigs. Nevertheless, there is a certain risk, and the optimal bypass has to be carefully determined in the pig design. For design and optimization of dewaxing bypass pigs, O’Donoghue25 has proposed a “continuity principle”, stating that “the rate of bypass through the pig (Qbypass) should be greater than the rate of wax approaching the pig (Qwax)”, i.e., Qbypass > Qwax. It is then assumed that a solid plug of wax cannot build up ahead of the pig because oil is always flushing it away. Qbypass and Qwax are given by
control method. Pigging frequencies may range from every 2−3 days to every 6−12 months. With difficult fluids and complex transport systems, sometimes including multiple diameters, thorough planning and testing of pig design and procedures are extremely important to optimize operations and minimize the risk of stuck pig incidents. Dual-diameter scraper pigs for wax removal in the smallest bore are currently in use. There is, however, limited experience and knowledge about wax removal in the largest bore of a dual-diameter system. In-house tests indicate that up to about a 20% diameter increase can be handled with soft wax, but hard wax removal is much more difficult. In fact, removal of hard layers of wax close to the pipe wall is challenging even with constant bore. This is an area where firm knowledge is rather limited, i.e., how the consistency of wax layers varies with conditions of fluid composition, shear, heat loss, aging, etc. This may not be so important for capacity but is extremely important when wax layers have to be completely removed in preparation for pipeline inspection. There are several reasons why the oil industry needs to have good criteria for determining the wax pigging frequency as accurately as possible. In many cases, particularly subsea multiphase flow lines with regular round-trip pigging, which have to be depressurized before pigging with dead oil, there is a cost issue related to shutdown and deferred production. Without a good basis for setting correct criteria, there is a tendency to be somewhat conservative. There have been some cases in North Sea oil export systems where one has temporarily lost track of wax-cleaning pigs or pig modules. Because of risk of getting stuck when sending another cleaning pig without knowing exactly where the first one is, it has been necessary to quickly assess the risk of extending the pigging interval beyond the established practice versus shutting down production until the pig has been located. In one such case, the pigging frequency of the 115 km, 28 in. pipeline from Oseberg field center to the onshore Sture terminal was every 4 days. Without extending the pigging interval to at least 2 days, a number of fields with a total production of 225 kbbl/day would have to be shut down temporarily. On the basis of experience from a nearby analogue pipeline, where the normal pigging interval had been extended without problems, it was decided that an extension of pigging interval from 4 to 10 days would be safe, thereby avoiding an expensive shutdown. The lost pig module was located within 2 days. This case illustrates the importance of a good basis for setting pigging criteria. With more and more complex, multinode oil export systems in the North Sea, scenarios with multiple pigs present in pipelines feeding into a common trunkline have become a concern when all feeding lines need regular wax control. One 4128
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2ΔP Abypass ρ
Q wax = Nvpigπdtwax,daily
Norwegian continental shelf. Examples are Statoil’s Kristin, Kvitebjørn, and Vega fields. Still, the experience from Erskine and, particularly, the multiphase pipeline pigging are valuable. However, because of important differences in terms of a longer transport distance, higher gas/condensate ratio, diameter variation, need for subsea pig launching, and wax removal in a flexible riser, the recent Vega field development introduced several additional wax control challenges that had to be addressed. The Vega development (startup 2010) comprises three gas condensate fields in about 380 m water depth, which are linked in series by a 51 km dual diameter (12 in./14 in. inner diameter) wet-insulated multiphase pipeline to the Gjøa platform. The U value is 4 W m−2 K−1 for the flow line and 7 W m−2 K−1 for the flexible riser. The reservoir pressure is 550 bar, and the reservoir temperature is about 135 °C. Monoethylene glycol (MEG) is used continuously for hydrate control. The CGR is ca. 500 Sm3/MSm3 initially, first slightly increasing, and then decreasing to ca. 125 Sm3/MSm3 toward the end of field life. The WAT of the stabilized condensate is typically around 35 °C, while live oil WAT at operating conditions is around 30 °C. Wax deposition tests with stabilized oil, carried out in Statoil’s in-house 1 bar, 2 in. wax deposition test rig6 with realistic conditions (temperature gradient between the bulk and pipe wall around 0.1 °C and wall shear stress in the range of 2−8 N/m2), have shown that wax deposition at a wall temperature of 30 °C (about 5 °C below WAT) is very moderate and then increasing sharply below about 27 °C. The tests performed with stabilized condensate are considered to be on the conservative side, indicating that transport temperatures somewhat lower than 27 °C can be allowed without significant wax deposition. Because of well problems on the template farthest away from the processing platform, flow rates have been lower than expected since startup in 2010, with lower than expected arrival temperatures as a result. Launching of pigs from the subsea pig launcher at this template has not been possible. To mitigate the lower temperatures, the arrival pressure at Gjøa was increased from 75 to 100 bar, thereby reducing the subsea choking and associated Joule−Thomson cooling and increasing arrival temperatures by several degrees. Experimental wax deposition data have been very important when evaluating the risk of postponing the first pig operation. There have only been short periods with an arrival temperature lower than 27 °C, and a wax inhibitor, qualified for Vega, has been used in periods with low flow rates. There are no indications of wax deposition in the system, but some deposit may be present in the flexible riser. A special feature of gas condensate reservoirs, such as Vega, is the compositional development that typically occurs as the reservoir is depleted and retrograde liquid drop-out occurs in the reservoir. As shown in Table 1, the predicted CGR of produced well stream decreases by a factor 4−5 during the first 10 years as the reservoir pressure decreases from nearly 500 bar initially to 60−70 bar. In a kind of “constant volume depletion” process, the produced gas becomes significantly leaner and waxforming components are gradually reduced. The corresponding late life (simulated) WAT of produced condensate is seen to be far below 0 °C. This means that, although flow rates and arrival temperature become lower, the wax potential becomes smaller and smaller. Because the actual (field) compositional development is somewhat uncertain, the effect has not been taken into account in the wax control strategy for Vega, but it will be
(1) (2)
respectively, where Cd is the discharge coefficient or actual discharge/ideal discharge, typically 0.7 (deviation from ideal flow through bypass orifice), ΔP is the pig differential pressure (Pa), ρ is the oil density (kg/m3), Abypass is the bypass area (m2), vpig is the pig velocity (m/s), d is the pipeline internal diameter (m), twax,daily is the daily deposition at the peak of the deposition profile (m/d), and N is the number of days since the last pigging. In terms of fractional bypass area (i.e., bypass area divided by the cross-sectional area), xAbypass, the required pigging frequency N can then be obtained using the continuity principle. Cd N
