Summary. Gravel packing is unattractive as a way to protect against the effects of sand production in subsea wells because it involves additional completion costs, loss of productivity, and difficulties in subsequent recompletion/well servicing operations. On the other hand, omitting gravel packs means that subsea developments must be designed and operated so that they can tolerate sand production. An experimental study was carried out on sand transport and deposition in multiphase flow in modeled subsea flowlines to address the problem of sand collection in horizontal trunklines, which could lead to reduced line throughput, pigging problems, enhanced pipebottom erosion, or even blockage. This study led to the definition of a new model for sand transport in multiphase flow, which was used to establish the risk of sand deposition in trunklines connecting a subsea development to a nearby production platform. Introduction Several small North Sea discoveries can be developed only as subsea satellites of existing production platforms, given current oil and gas economic constraints. These constraints also dictate simple underwater manifold centers and simple, minimum-maintenance subsea completions, with high productivity per well. Conflicting demands arose during the development of several small offshore fields when calculations based on in-house sand failure criteria indicate-d that the wells were potential sand producers. For various reasons (e.g., completion complexity, loss of production potential, or interference with anticipated acid stimulation), the use of sand exclusion techniques during completion of these wells was considered undesirable. Thus, these developments had to be designed to be "sand-tolerant"; i.e., sand produced by the wells had to be collected in separators at the production platform several Kilometers from the sandface without damaging the intervening production equipment or the processing facilities on the platform. In one particular development producing oil with a low GOR (so velocities in the trunklines carrying the oil to the platform generally would be low), sand deposition was considered the main risk. Such deposition and the formation of (moving) sand beds at the pipe bottom had caused several problems: reduced line efficiency owing to (partial) blockage of the lines and increased frictional pressure loss, enhanced pipe-bottom erosion/corrosion owing to a high concentration of solids at the bottom and the formation of corrosive cells beneath the sand beds, and malfunctioning of equipment owing to sand deposition at critical parts. These problems can be avoided by ensuring that the capacity of the lines to transport sand to the platform exceeds the total sand production of the wells connected to the lines. This requires knowledge of the flow of gas/liquid/solid mixtures through horizontal flowlines and the vertical riser section to the platform's production deck. Although the flow of sand/water slurries has been studied extensively (e.g., for hydraulic engineering purposes, data on three-phase sand/gas/liquid flow are unavailable in the literature. Therefore, a project was begun to collect such data in the laboratory and translate the results to field conditions. This paper describes the experimental methods used to study sand transport and deposition. The results and their interpretation in terms of the relations between dimensionless parameters are discussed. Finally, this paper shows how these relations can be applied to field conditions and their consequences on design and operation of subsea trunklines. Experimental Methods The experiments were carried out in an air/water/sand test loop with a 0.070-m ID. Fig. 1 shows the layout of this loop schematically. Three methods were used to monitor the transport and deposition of sand injected into the air/water flow.Visual Observation. A transparent test section was included in the loop some 50 diameters from the sand injection point to minimize entrance effects. This allowed sand transport modes to be determined and sand-bed widths to be estimated by direct visual inspection.Sampling. A full-bore sampling probe was installed in the riser section. This allowed total sand transport through the system to be determined by passing the suspension over a 100-um filter.Acoustic sand detection. A clamp-on sand sensor was mounted at the bottom of the last horizontal section to study the mechanics of sand-grain movement under multiphase conditions. Four liquid/gas/solids systems were studied with this equipment. Series A - air/water with sand-grain size (0. 15 to 0.30 mm, input gas volume fraction of 0% to 20%, liquid velocity between 0.1 and 1.2 m/s, pressures slightly over atmospheric, room temperature of about 20C). Series B - similar to Series A, but with larger sand grains (0.69 mm) to simulate the effect of clustering of smaller grains. Series C - water viscosified with carboxymethyl cellulose EHV, giving it an effective viscosity of about 7 mPa - s, and a grain size of 0.15 to 0.30 mm. This system was used to investigate the effect of viscosity on sand transport (the viscosity may vary considerably over the trunklines as a result of liquid cooling). Series D-air/water with surfactant added to the water to reduce the surface tension from 0.064 to 0.028 N/m (further reduction was impractical in view of the increasing tendency to foam), with a grain size of 0.15 to 0.30 mm. This system was used to study the effect of surface tension, which is considerably higher in an air/water mixture than in an oil/gas mixture, Some 270 tests were carried out, resulting in a large volume of data over a wide variety of parameters. Results and Discussion To approach the vast amount of data systematically, the (qualitative) observations on the sand transport mode will be discussed first. The measured sand transport then will be analyzed in terms of the appropriate dimensionless quantity. Finally, some data on particle movement at low flow rates will be discussed. Sand Transport Modes. Three sand transport modes and two fluid flow modes can be distinguished visually. The sand transport modes are as follows. 1. Stationary bed. At the lowest liquid velocities, the injected is deposited at the bottom of the pipe. This leads to local sand buildup as injection continues. 2. Moving bed. Above a certain critical velocity (which is a function of pipe ID, grain size, and liquid and solid density and viscosity), the grains start to move, initially as dunes, at higher velocities as a continuous sand bed. SPEPF P. 237^
The problem of annular pressure buildup due to heating of the strings by the (hot) well effluent, will typically be of concern in the design of casing strings for high-pressure/high-temperature (HP/HT) subsea wells. In such completions bleeding off the pressure through the wellhead, as done routinely with surface wells, is not possible.Theoretical studies indicated that, potentially, extreme pressures could develop in confined sealed annuli of subsea completions, posing a severe threat to well integrity. To investigate the effect under realistic conditions, Shell Expro (UK) ran battery operated gauges in the 9 5/8 in. 13 5/8 in. annulus of an offshore HP/HT well, to record pressure and temperature changes during drilling, cementing and production testing.This paper presents the results of these tests and a general model for pressure buildup in unconfined sealed annuli to correlate the field data. Since only pressure and temperature measurements were available certain assumptions had to be made with respect to, e.g., formation response to pressure buildup, in situ liquid properties, etc. Although these assumptions could be debatable, it is hoped that by publishing and sharing ideas, a better understanding of annular pressure behavior can be developed.
Summary Pressure buildup, caused by fluid thermal expansion in sealed annuli of high-presure/high-temperature (HP/HT) wells, can have serious consequences such as casing failure or tubing collapse. To determine whether mitigation was required for a HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test, which consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well, and testing the well several times during a 3-month period, after which the gauge was retrieved, and the data were read out. First of all, comparison of the magnitude of the observed annular pressures with the burst and collapse ratings of the casings shows that annular pressure buildup is a serious consideration in casing design. Such design is to be based on theoretical models for annular pressure buildup. The data acquired with the test serve to validate these models. The data demonstrate that, in general, the theoretical models overpredicted pressure buildup in the annulus. This overprediction was more pronounced at higher temperatures (and pressures) than at lower temperatures, which could not be explained by mechanical factors such as casing ballooning. The influence of these factors was quantified by analyzing the transient pressure response of the annulus. Neither could permanent leakoff of completion fluids explain the discrepancy between theory and test. Leakoff of the annular fluids, which was seen to dominate pressure development during a previous test in a well with a cement shortfall between casings, does not play a significant role in this fully cemented and sealed annulus. This left (1) the properties of the completion fluids differing from the properties of the base fluid (water), and (2) temporary leakoff to near-wellbore fracture systems through the microannuli between cement sheaths and casings as explanations for the observed overprediction. Therefore, estimates on the basis of pure water properties, considering the annulus to be a perfectly pressure-tight vessel, can be considered a worst-case estimate for pressure buildup and a safe basis for design. Introduction Pressure buildup in tubing-casing or casing-casing annuli is, in general, undesirable. Although casing design should take into account high pressures at the casing head (e.g., caused by leakage or thermal expansion of the annular fluids), high-pressure differences always hold the risk of the casing bursting or collapsing at weak points, leading to loss of production (Vargo et al. 2002) or in the worst case, loss of the well (Nelson 2002). For this reason, most operating companies adhere to annular-pressure-management schemes for onshore and platform wells, which prescribe bleeding off pressure through the wellhead once a predetermined pressure level (e.g., 20% of the minimum internal yield pressure of the affected casing) is reached.
Summary A series of field tests on liquid loading of gas wells demonstrated that various types of behavior could be encountered in such wells. On the basis of the test results, an improved model for predicting the performance of gas wells producing liquids was formulated. This model takes into account multiphase reservoir performance and the vertical flow performance of the tubings for wet gas. It provides improved estimates for performance of the tubings for wet gas. It provides improved estimates for gas deliverability and the remaining life of watering-out gas wells, compared with common methods that calculate "critical" conditions at a single point (usually the wellhead) in the tubing string. Introduction An increasing number of gas wells drilled into the northwest European Permian basin have experienced water influx. This usually happens after 3 to 8 years of production when, owing to depletion, aquifer influx and (partial) flooding of the reservoir occurs. Water coning may precede water influx. Water production initially affects well productivity only marginally; at high gas rates, the well's capacity to produce liquids continuously to surface exceeds the rate of water influx. With continuing depletion, however, the gas rates decrease and liquids can accumulate in the wellbore. This liquid holdup exerts an additional pressure on the reservoir, further curtailing production. An increasing water saturation around the well-bore aggravates this effect. Eventually the well will "load up" with liquids and cease to flow. Either workover techniques for shutting off the water-producing zones (cementation and reperforation) to improve the well performance (recompletion with small-ID tubing) and to lower the performance (recompletion with small-ID tubing) and to lower the well-head pressure (compression) or artificial lift (e.g., plunger) may be required to restore production. These remedies for loading are costly and time-consuming. Hence, accurate methods of determining the optimum timing of workovers, installing compression, and evaluating their eventual results are essential to ensure that investments in watering-out gas fields are justified, that forecasted gas production meets negotiated contracts, and that additional wells are drilled in time. The following section briefly reviews published methods for predicting loading and their drawbacks. Then the proposed model, predicting loading and their drawbacks. Then the proposed model, which circumvents these drawbacks by taking into account both multiphase reservoir performance and tubing performance, is discussed. A comparison between field test data and model calculations demonstrates the validity of the approach. Current Methods Traditionally, "liquid loading of a wet gas well" was used to indicate that the bottomhole flowing pressure (BHFP) of the well could not be determined accurately from the surface production data and that liquid was produced to surface irregularly, so sampling to determine liquid (condensate and/or water) production gave erroneous results. These phenomena can be considered to be related to a change in flow regime from continuous (annular) mist flow to intermittent flow patterns, such as slug or churn flow. A large pressure drop over the tubing and rapid fluctuations in the gas/liquid pressure drop over the tubing and rapid fluctuations in the gas/liquid ratio are typical of the latter flow regimes. Of course, the change in flow regime does not necessarily mean that the well will cease to flow; this is determined by the total system performance, as shown by the following discussion of methods for predicting the onset of loading. An early approach to predicting the onset of liquid loading in gas wells was to define a minimum gas velocity at wellhead conditions of 5 ft/sec. Later work showed that wet-gas wells could cease flowing when wellhead velocities were less than 16 ft/sec. This indicates that the 5-ft/sec criterion cannot be considered generally applicable. This restriction also applies to the approach advocated by Ilobi and Ikoku that is based on a model for tubing-wall liquid film transport. Comparison of the model with available field data did not allow an unambiguous identification of the film flow conditions under which wells would load up. Hence, general use of this method cannot be recommended.
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