Abstract The production, transport, and refining of petroleum and gas are constantly affected by the deposition of unique phases such as wax, asphaltenes, diamondoids, hydrates and sulphur. The venue of the advanced acoustic resonance approach has been successfully tested to meet the challenges of solids problems in the new millennium. A mercury-free advanced acoustic resonance (AR) system, developed and tested at Hycal Energy Research Laboratories for reservoir applications, makes it possible to have fast, highly accurate, measurements during depressurization (9000 psia to 12000 psia) runs on dark live oil at reservoir temperature to identify the onset of asphaltenes precipitation and bubblepoint during the same run. Black oil, a problem for visual and optical methods, is no barrier for this technology. Effects of inhibitors on solid-liquid equilibrium have been investigated at various concentrations and temperatures. The results are presented and discussed. EOS modeling of the AR results have been presented with comparisons. There is good agreement between measured and modeled data. Introduction Asphaltene precipitation from reservoir fluids causes severe operational problems in the wellhead equipment, separators, tanks and surface equipment 1 . In offshore production, the clean-up costs have skyrocketed 2 . Asphaltenes are dark brown to black solid compounds with no definite melting point. They decompose while heating and leave a carbonaceous residue. They are non-crystalline substances or mixtures of relatively high molecular weight fractions of bitumen with characteristics of strong aromatic polar substances. They are classified by the particular solvent (nheptane, n-pentane) used to precipitate them 3 . Asphaltene precipitation can be measured experimentally. Light-scattering techniques4 and cross-polarization microscopy 5 have been used to determine the onset of solids precipitation experimentally. Poor signal to noise ratio limits the dynamic range of operation in the case of N.I.R. An advanced acoustic resonance system developed at Hycal has been successfully used in the determination of solids precipitation onset in live reservoir fluids. The system exploits the time evolution of the acoustic response in fluids under variable and well-controlled conditions of pressure, volume and temperature 6,7 . The system detects phase transitions on the basis of differences in orders of magnitude in sonic speeds of various fluid states (vapor/liquid/solid) when acoustic waves are propagated in a reservoir fluid going through phase changes. EXPERIMENTAL DETAILS Hycal's AR system, consisting of a cylindrical resonator (0.25 inches in diameter) is made of hastelloy with one transducer at the top to generate acoustic waves through the fluid in the resonator, and the other at the bottom to receive the signals that carry information about the fluids through the phase transitions. One can detect the onset of liquid-solid or liquidvapor transitions in fluids by analyzing the acoustic responses. The assembly is housed in a well-insulated circulating airbath with precise temperature control from -40 °C to 150 °C. A digital pressure gauge is used to measure pressures up to 10,000 psia and a platinum resistance thermometer is used to measure temperatures precisely. A linear velocity displacement transducer arrangement is used to accurately measure the volume at any instant in time.

Abstract It is well known that microbubbles play an important role in heavy oil reservoirs, where the presence of asphaltenes and other charged particles makes it easier to generate microbubbles. Only recently, however, microbubbles are being considered for rigorous analysis of primary depletion in heavy oil reservoirs. Previous studies show that the conventional analysis that relies on PVT data as the only independent variables of the system is not adequate in explaining why recovery is significantly higher than the one predicted by Black-oil reservoir simulators. In this study, the role of microbubbles in altering PVT properties will be quantified through a series of PVT data. It is expected that the PVT properties are significantly altered due to the presence of asphaltenes, with a complex dependence on the asphaltene concentration. Also important is the nature of the gas phase present in the system. The microbubble capture and retention due to the presence of asphaltenes make the bubble release time much longer than when the asphaltenes are absent. This phenomenon has not been accounted for in the past. A new equation of state is generated that satisfies the PVT data for various asphaltene compositions. Also introduced is a transition factor that includes the effect of the history of the bubble generation. This equation helps explain several factors (e.g. delay in bubble release from heavy oil, greater than expected recovery from primary depletion of heavy oil formations) that have eluded scientists in the past. Introduction The context of this paper requires that one discuss the role of microbubbles in heavy oil recovery as well as the useful form of currently used equations of state. The literature on the first topic is scarce. The latter subject, however, has seen extensive research activities in recent years. Microbubbles in heavy oil recovery The study of microbubbles is an active topic of research for petroleum and other fluids applications. Some notable research studies performed outside of the petroleum field determined that microbubbles carry an electric charge 1 . This information was later used to develop the relationship between frequency and ultrasonic generation of microbubbles 2 . Early petroleum research into microbubbles and their relationship to asphaltenes was carried out by numerous researchers (3–6) . Smith 5 was possibly the first researcher to hypothesize that the existence of microbubbles can explain the possibility of recovering more oil from heavy oil reservoirs than that predicted by primary depletion theory. Islam and Chakma 6 conducted a series of experiments to demonstrate that the hypothesis of Smith 5 was correct. They further demonstrated that the capture of microbubbles can be correlated with the asphaltene content of a crude oil. Islam 7 summarized these findings and concluded that the charged nature of asphaltene particles must be responsible for increased bubble captures. He argued that a new theory should be presented in order to accommodate for microbubbles that show considerable delay in release from liquid than do ordinary gas bubbles. This theory, he contended, should be able to explain more-than-expected recovery from heavy oil reservoirs.

Abstract In the paper, a distribution of some rare elements in the heavy crude and bitumen-bearing rocks, Tatarstan, is discussed. The extracts from bitiminous rocks, alphaltenes, and rock samples are studied by means of inpa-red spectroscopy, thermal analysis, and specrophotomehy. The distribution of a number of elements was investigated in chloroform, alcoholbenzene extracts, qhaltenes and bitimen-containing rocks of Tatarstan. Bitumen content in the rocks was not more than 3 mass %. V, Cr, Mn, Ni, Cu, MO, Ag, Au and some other elements concentration is evaluated. The data obtained count in favour of the theory of primary metal-bearing asphaltenes generation. The presence of outcrops of vanadium-bearing rocks or vanadium-containing ore bodies (characteristic for regions with great segregation of vanadium-bearing oils) in the immediate proximity of deposits of vanadium-bearing oil objects points, firstly, to a source of secondary enrichment in vanadium and, secondly, to a possibility of prediction and prospecting element-containing ores or ore bodies by their abnormally high content in oils and bitumens. Introduction Development of bituminous rocks with high content of unconventional hydrocarbon stock concerns the production of synthetic oil. With a low bitumen content in rocks, the problem is more complicated. The elaboration of recommendations on development of these deposits calls for a comprehensive research on composition of bitumens and their embedded rocks. Elucidation of some fundamental problems in petroleum chemistry, particularly in bitumoid metallogeny, is possible as a result of this study. One of genetic models for metal-bearing oils generation was based on metals transfer from a rock during their migration and within the deposit. However, a mechanism of rock elements intrusion into oil is controversial due to inertness of reducing systems relative to mineral matrix. Organic matter interacts with rock components forming complex, ionic and sorption bonds at all stages of geological evolution This organic matter is converted into an insoluble carbonaceous substance (kerogen) as a result of overall changes in the course of sedimentation, diagenesis, catagenesis and metamorphism. Metamorphism of magmatic and thereafter sedimentary rocks is likely to cause a redishibution of elements between neogenic mineral phases and transformed organic matter. Fragments of kerogen or a molecule of transformed organic matter may serve as asphaltene nucleus as evidenced by resemblance of spectra obtained for insoluble carbonaceous matter and the most high-molecular fraction of asphaltenes. EXPERIMENTAL Bitumoids were extracted from the rock by applying chloroform and alcohol-benzene mixture in accordance with a routine procedure. Infrared spectra were obtained at IFS-113V Bruker Fourier spectrometer, with wave range being equal to 4000- 400 cm −1 KBr powder was utilized for the sample preparation. The content of vanadyl porphyrins (VP) and nickel porphyrins was evaluated by means of spectrophotometric method, owing to adsorption intensity peaks at 570 mn for VP and at 550 nm for NP, by using extinction coefficient being equal to 2.9x10 4 and 2.7x10 4 l/mdcm, respectively, while estimating [I], The concentration of rare elements was determined by means of X-ray fluorescent technique (WA-20 analyzer) and flaming atomic-adsorption spectroscopy (AAS-1N and Z-6000 Hitachi spectrophotometers) [2].

Abstract To combat scaling problems in the course of production, pollution control and water disposals through analyses of formation waters, their chemical activities and scale forming tendencies, are necessary. In this regard, a large number of formation water analyses of different giant oil field fractured carbonate reservoirs in Iranian Onshore Offshore fields, many close to saturated conditions, are obtained, processed in standard forms and graphical presentations. computational study of the acquired data lead to development of a simple empirical correlation capable of predicting scale tendencies of the formation waters in the subject fields Well established models verified the validity of the simple model in different parts of an oil desalting unit under operation The paper & scribes in details how the simple empirical correlation was developed. Introduction Very frequently, the results of tests on commercial oil and gas wells show good production potentials. Immediately after being put on stream or at some time during their productive life a decline in production occurs, which could well be due to problems in mineral scale in the form of calcium carbonate, bark sulfate and calcium sulfate, deposits occurring at some point in the producing system and restricting the flow of production. This deposit can occur at any point from the time the produced fluids, which always contain water with dissolved mineral matter, begin to move along minute channels into larger channels and eventually into the wellbore, up the tubing string, and through well head assembly. At any point in this route, the minerals have the opportunity to come out of solution and deposit The deep high pressure wells typical of Iranian oil fields (carbonate reservoirs) are particularly subject to scale formation (CaCO 3 ) because of high CO 2 partial pressure due to action of bacteria, abundance of organic sources at high pressure to form soluble calcium bicarbonate. Scale causes a large number of costly pulling jobs, perforation reamings, redrilling, stimulation and other remedial works periodically. Thus, through understanding of the mechanism of scale formation in Iranian oil fields, identification of the techniques of their prevention and remedial actions, are indispensible. CAUSES OF SCALE DEPOSITION The causes of scale and other fouling deposits related to saline waters are many, varied and extremely complex. Numerous investigators have studied scale and deposit mechanism in an effort to understand, quantify and develop remedial or preventative treatments. For example, Spiegler (1) ) point out that crystallization from solution of a material directly on site of scale formation requires three simultaneous factors: supersaturation; nucleation; and adequate contact time. Supersaturation are solutions that contain higher concentrations of dissolved solute than their equilibrium concentration. The causes of supersaturation may be due to: temperature fluctuation, pH alteration, addition of seeding material, commingling of two incompatible waters, pressure reduction, agitation, evaporation, etc. Nucleation or the initial formation of a precipitate can occur for many reasons, e.g. dust particles, vibration, etc. Two basic nucleation mechanisms are recognized: homogeneous nucleation and heterogeneous nucleation which opposite to the homogeneous case requires a pre-existing foreign crystalline substance.

Abstract A high ratio of success has been seen in removing formation damage from older heavy oil wells using an asphaltene suspending agent in conjunction with a selective stimulation tool. Treatment involves spotting the agent at the formation face and in the immediate well bore region, allowing it to soak for a minimum of 16 hours, and then over flushing with a high volume of light crude at sub fracturing pressure. Results are shown from a number of wells from three different fields. Incremental production has been as high as 8X and has been sustained for as long as 18 months. Introduction Determining whether or not a well is producing to its maximum potential and, if not, how to remedy the situation is never a simple task. Notwithstanding, there are certain factors which can make a given problem within a given field more likely to occur than others. An excellent example is asphaltene problems in heavy oil wells. Asphaltenes are highly aromatic compounds containing small amounts of sulfur, nitrogen, and oxygen which give rise to a molecule with a partially positive charge. The resulting structure is held together through π - π, hydrogen and acid base bonding whose molecular weight has been reported to be a function of its environment: environments that favor dissociation of the individual units, such as higher temperatures and higher degrees of solvent aromaticity, result in lower molecular weights and thereby result in suspension; conversely, environments that favor association, such as lower temperatures and less aromatic solvents, result in higher molecular weights and thereby result in flocculation and precipitation. 1 Typical Lloydminster heavy crude contains between 12% and 15% asphaltenes by weight, although it can contain as much as 22% in some fields. Essentially insoluble in oil by themselves, asphaltenes are held in suspension in oil by natural surfactants called resins. However, the bond holding the resins to the asphaltene is rather weak; resins can be stripped from the asphaltene through contact with light end alkenes as well as through variations in temperature and pressure. 2 Thus, asphaltene precipitation can occur through the production process itself (due to decreased temperature) or can be induced through the use of loading fluids containing high amounts of light end alkenes. When asphaltenes do precipitate, it is likely that they will crystallize on a negatively charged solid, such as sand or clay. If the crystal is produced along with the sand, this precipitation does not represent a production problem (although it may cause a subsequent treatment problem). If, on the other hand, the sand / asphaltene conglomerate is not produced and enough sand is held together by this asphaltene type ‘cement’, the wellbore can eventually clog. Producing heavy oil through this blockage would be similar to filtering cold molasses through a high mesh filter. Methods used to correct inflow problems due to asphaltenes have typically involved re-perforating or the use of solvents, either alone or in a "blend" with oil. Historically, re-perforating heavy oil wells gives a short term increase in production.

Abstract A new technique for the determination of the onset of asphaltene flocculation (OAF) has been developed through viscosity measurement of the oil mixed with a gaseous solvent under miscible conditions. A capillary tube was used for the viscosity measurements. The method is based on the detection of a sharp increase in the viscosity of the oil-solvent mixture, at increasing concentrations of precipitating solvent. High pressure experiments with three oils, and propane as an asphaltene flocculent, were performed. For these oil-propane systems the OAF values determined by the new method were compared to those obtained using a photometric method. In the new method, detection of OAF caused by hydrocarbon solvent gases at high pressure, is done in a very straightforward way, and does not require any reference curves on oil mixed with non-precipitating solvents (i.e. toluene, benzene, etc). The main advantage of the new method as compared to the photometric methods, is that it is applicable for both light and heavy oils, and no dilution with toluene is necessary. Introduction The oil industry has faced the problem of asphaltene deposition for many years. Asphaltene deposition in the reservoir, well bores, well head equipment, pipelines and other downstream equipment can lead to serious problems and can increase the cost of producing oil. Presently, most methods for dealing with the asphaltene problem are remedial in nature. It would be highly desirable to use preventive methods to combat asphaltene deposition or at least to reduce the late of asphaltene deposition, thereby decreasing the cost of remedial techniques. The test methods used to determine the propensity of oil to deposit asphaltene are more complicated in nature. For this reason, given the diversity of laboratory procedures, very often, contradictory results are presented for the same combination of oil and a flocculating agent. Asphaltene deposition increases whenever anything disrupts or destabilizes the asphaltene-resin micelles. For example, the addition of low-molecular weight hydrocarbons - such as propane, n-pentane, petroleum naphtha or gasoline - will flocculate asphaltenes by solubilizing resins in the bulk oil phase. There are two different types of asphaltene deposition: - Asphaltene deposition during primary recovery of oil, which is due mainly to the changes in pressure and temperature. - Asphaltene deposition during miscible flooding involving rich hydrocarbon gases and carbon dioxide. For the latter, the most important problem is to determine the minimum amount of solvent gases that would trigger the flocculation/deposition process, at the prevailing pressure. The quantity of asphaltene so deposited is also of interest. Determination of Onset of Asphaltene Flocculation Using Light Scattering Method As mentioned, accurate determination of onset of asphaltene flocculation (OAF) and onset of asphaltene deposition (OAD) are very important for the choice of methods for preventing/combating asphaltene deposition. To the best of our knowledge, there are no methods for the determination of OAD, while there are several methods for determining of OAF having different accuracy and difficulty. The most important methods for OAF determination are: a) light scattering method, b) gravimetric method, c) interfacial tension measurement between water and oil upon dilution with a precipitant agent, and d) visual method.

Abstract Reservoir fluids containing paraffin's and asphaltene's are common in the petroleum industry. The presence of these components causes significant operational problems during the life of the producing wells. The identification of wax and asphaltene precipitation conditions is the first step towards applying any remedial options. There are various procedures applicable in determining the onset of wax and asphaltene precipitation conditions. These techniques are dependent on the oil characteristics. The most important criterion is the colour of the oil. For dark coloured oil, the popular light-scattering technique becomes inadequate. In this case, near-infrared (NIR) light spectrum is necessary to identify any changes in the response due to phase change phenomenon. An emerging technology, called Acoustic Resonance Technology (ART), has been tested at Hycal Energy Research Laboratories Ltd. to identify the onset conditions of wax and asphaltene precipitation. The system is applicable to any type and colour of oil. The basic principle behind the technique is the transmitting of sound waves through the fluid while it is exposed to wax or asphaltene precipitation conditions by changing pressure, temperature or composition conditions. The acoustic response shows drastic changes during the phase transition (i.e. nucleation of wax or asphaltene) in the fluid. Initial results of the onset of wax and asphaltene precipitation are extremely promising. Comparison of the onset values of wax and asphaltene precipitation using ART showed excellent agreement with that obtained using a light-scattering technique. Introduction Acoustic Resonance Technology (ART) is based on measurement of the response of a fluid or fluids, contained in a cylindrical cavity, to acoustic variable stimulation. The most powerful use of ART is to study the state and time evolution of the resonance response of fluids under variable and well controlled conditions of pressure, volume and temperature. 1,2,3 In these cases, one can obtain information related to fluid phase behavior or phase transitions and transport properties. ART offers a sensitive, objective method for probing and measuring bulk fluid properties and processes. Asphaltene's are dark brown to black solid compounds with no definite melting point. They decompose while heating and leave a carbonaceous residue. They are non-crystalline substances or mixtures of relatively high molecular weight fractions 4 of bitumen with characteristics of strong aromatic polar substances. 5,6 Asphaltene's are defined as the n-heptanes insoluble fraction of crude oil. 7,8 They are classified by the particular solvent used to precipitate them. 9 They are generally soluble in benzene and insoluble in low molecular weight n-alkenes. 10 Asphaltene precipitation can be determined experimentally. Waxes are defined as normal paraffin's as well as other molecules containing long chain alkyl groups usually ranging from C 18 to C 60 . Solid waxes crystallize or precipitate when cooled below their cloud point temperature. The wax precipitation process is thermodynamically reversible. 11 The viscosity of crude oil is increased by the presence of the wax crystals. 12 lf the temperature is reduced sufficiently, the crude can become highly viscous and approach its pour point temperature. Solid (waxes and asphaltenes) precipitation from reservoir fluids causes severe operational problems in the subsurface, surface equipment, wellhead equipment, separators and tanks. 13,14 Clean-up costs can be very high in off-shore oil product

Abstract A heat transfer technique for the detection of the onset of asphaltene precipitation is presented and its versatility demonstrated. The technique is able to evaluate the effectiveness of asphaltene precipitation inhibitors, and solvents used to resuspend a deposit. It can also be used to study the reversibility of asphaltene precipitation. A number of chemical species were tested for their ability to delay the onset a/precipitation. The nonionic surfactant nonyl phenol was the most effective chemical tested. Toluene and xylenes were shown to resuspend an-heptane precipitated deposit, and it was found that xylenes were, in general, more effective. Temperature traces indicate that the redissolution of precipitated asphaltenes upon n-heptane removal is reversible but incomplete. It is possible that the dissolution process may have proceeded further had longer dissolution times been allowed. Introduction Asphaltene flocculation and precipitation remains a problem to petroleum production, refining, and upgrading operations. During production, asphaltenes may precipitate in the reservoir, well, or separation equipment leading to reduced production. In refining and upgrading, asphaltene flocculation and precipitation is acknowledged as the first step in the formation of coke, an unwanted product. The asphaltene fraction is defined as the material of a petroleum sample that is soluble in toluene and insoluble in the solvents n-pentane or n-heptane at a dilution of 40 millilitre solvent per millilitre petroleum. Being a solubility class, the asphaltenes compose a large number of different molecules. Which are usually very difficult to separate. The methods used to isolate asphaltenes, and the influence of various parameters such as solvent type and contact time have been presented by Speight et al. 1 . Asphaltenes are the highest molecular weight species, contain the largest weight percent of the undesirable heteroatoms nitrogen, sulphur, and oxygen, and are the most aromatic fraction of a petroleum (Speighr 2 ). When considering the stability of petroleum, it is known that a balance between the three pseudo-components: oil, resins, and asphaltenes is required. The resins fraction is responsible for keeping the asphaltenes in colloidal suspension, as was emphasized by Pfeiffer and Saal 3 . The resins peptize the asphaltenes by acting as a transition between the aromatic polar asphaltenes and the non-polar aliphatic oils, thus preventing asphaltene flocculation and subsequent precipitation. The importance of the resins has been further emphasized by others, such as Nellensteyn 4 , Swanson 5 , Koots and Speight 6 , and Andersen 7 . In refining and upgrading processes, such as visbreaking, coking, and hydrocracking, where temperatures are typically in the order of 380 °C to 500 °C, reactions take place that cause the composition of the feed to change. In many of these processes, the net effect is that resins are depleted and the amount of asphaltenes increases (Lepage et al 8 , and Storm et al 9 , Wiehe 10 ). To prevent coking in these processes, which is a result of asphaltene condensation reactions, asphaltene flocculation and precipitation must be prevented. Feeds to these processes typically have 20 or more weight percent asphaltenes.

Abstract The deposition of asphaltenes in oil producing formations and production systems has caused problems for years. Selection of chemical control agents in the past has been limited to bulk dissolution studies on samples retrieved from production systems. Until recently, the accepted way to treat these problems has been through the use of xylene, toluene or other aromatic solvents. This method requires the use of large amounts of these solvents, as well as a high frequency of treatment. This paper desribes the results of field testing and application of asphaltene control chemicals, and the use of laboratory tests to select asphaltene deposition removal and prevention chemicals. Preliminary dispersant and solvency tests are conducted by an asphaltene dispersant test in hexane. Chemicals which provide promising results in dissolving and dispersing asphaltenes in the non-solvent medium of hexane are selected as candidates for field application, or for additional testing in a core flow deposition removal test. The core flow test apparatus provides a method to introduce asphaltene fouling into a core and study its removal by the use of chemical agents. Using core samples and asphaltenes from the production resource under consideration allows the selection of the best removal chemical. Introduction Asphiltenes are complex hetroatomic polar macro-cycles containing carbon, hydrogen, sulfur, and oxygen. They are large and highly aromatic in nature, and occur in crude oils as stabilized micelles. Resins and maltenes, which are molecular precursors of the asphaltenes, act to stabilize a dispersion of asphaltene particles. The asphaltenes are surrounded by the resins and maltenes polar heads, while their increasingly aliphatic tails extend into the hydrocarbon (oil) phase. When mechanical or chemical forces become sufficiently great, these stabilizing species are lost and the asphaltene particle becomes susceptible to interaction with a similarly destabilized asphltene leading to flocculation and precipitation. These destabilizing factors include: streaming potential caused by the fluid flow in the porous media of the formation which destabilizing asphltenes by electrical potential, mechanical factors, and by the addition of foreign agents. These agents can be acid or other stimulation or workover fluids, and recovery assist additives such as CO 2 or other miscible gases. These materials can destabilize the asphaltenes by changing the pH or the solubility characteristics of the crude oil. 1,2,3,4 Because the asphaltene particle is polar, it may take on a charge by induction resulting in secondary aggregation. As aggregation proceeds, accumulations of asphaltene macro particles appear. Bubble point effects are important because they represent the chemical stripping mechanism of destabilization. As the pressure drops below the bubble point, light ends encounter the aliphatic tails of the resins and maltenes causing a momentary imbalance in the character of the surrounding media. This momentary imbalance is sufficient to cause a stripping of the resins and maltenes and cause destabilization. Mechanical processes facilitate this action in several ways, but the most important of these is the movement of the crude from one pressure zone to another lower pressure zone.

Abstract Prior to the1977 offshore operations on Dome/Canmar's vessels in the Beaufort Sea, it was determined that hydrate formation could be encountered during gas well tests. Although systems had been developed for methanol injection in arctic land operations, offshore operations required a system which would retain the advantages of a sub-sea test tree. A system was developed by Dome/Canmar, in association with Johnston Testers, which allowed the injection of methanol up to 2,000' below the sub-sea test tree, and which would allow the unlatching of the sub-sea test tree, while maintaining the full pressure integrity of the test string. The system also allowed closing of pipe rams during testing (to activate down hole pressure controlled test tools) and re-latching of the sub-sea test tree, if it was required to temporarily move off a well. The system was successfully used throughout Canmar's 1977 testing operations. Introduction Hydrates will form and accumulate in a natural gas stream at predictable pressures and temperatures when the following conditions are met (1,2) : The pressure /temperature relationship of the gas must be below the dew point of the water vapour, and liquid water must be present. The gas must be in motion and subjected to a degree of turbulence. A foreign particle or a change in flow path must be present to interfere with the gas flow pattern. All three of these conditions can be expected to occur during gas well testing in the Beaufort Sea. Hydrates may form in the upper portion of the tubing string where the gas loses its greatest amount of heat and may accumulate further upstream in the flow head and manifold system where the gas is controlled before it reaches the heater. In each of these locations, hydrates may plug the flow path resulting in a termination of the production test and a loss of effective rig time due to the need for depressuring and clearing the system. On the other hand, hydrates can be prevented from forming by maintaining relatively high temperatures and low pressures throughout the flow stream or by fully inhibiting the water phase in the gas to lower the hydrate temperature. High temperatures can only be achieved after the well had been placed on stream for a time at high rates. However, during the initial flow period, inhibition is the only method that can reliably prevent the formation of hydrates. Arctic Operator Experience Of Hydrate Formation During Testing Several operators were contacted for field evidence of hydrate formation on gas well testing in arctic and offshore areas. On the North Slope, downhole hydrate prevention procedures vary. One method involves circulating hot calcium chloride solution down concentric strings until a suitable wellbore temperature is reached and the gas is maintained outside the hydrate formation pressure/temperature region. Gas well F.T.H.P' s in this case are in the range of 2,800 to 3,000 p.s.i.g. which requires a minimum gas temperature of approximately 75 °F to prevent hydrate formation, as shown in Figure 1.