February 2011, Vol. 238 No. 2

Features

Integrated Flow Assurance Solutions

Flow assurance is crucial for producing and transporting of oil and gas. The fluids – a combination of gas, crude/ condensate and water, together with solids – cause many potential threats like hydrate formation, wax/ paraffin, asphaltenes, scale deposition, sand erosion, emulsions and corrosion.

This article deals with integrated solutions and checklists for flow assurance strategy for conceptual design engineers. Moreover, an attempt is presented to provide a decision making chart.

Gas hydrates. These are solid crystalline compounds which have a structure wherein guest molecules are entrapped in a cage-like framework of host molecules without forming a chemical bond. It is water’s hydrogen bond that allows formation of hydrates. The hydrogen bond causes the water molecules to align in regular orientations. The presence of certain compounds causes the aligned molecules to stabilize and a solid mixture precipitates. The water molecules are referred to as the host molecules and the other compounds, which stabilize the crystal, are called the guest molecules.

The hydrate crystals have complex, three dimensional structures in which the water molecules form a cage and the guest molecules are entrapped in the cages. The stabilization resulting from the guest molecule is postulated to be caused by Vanderwaal’s forces, which is the attraction between molecules that is not a result of electrostatic attraction. The hydrogen bond is different from the Vanderwaal’s force because it is due to strong electrostatic attraction, although some classify the hydrogen bond as a Vanderwaals force.

Also interesting about gas hydrates is that no bonding exists between the guest and host molecules. The guest molecules are free to rotate inside the cages built up from the host molecules. This rotation has been measured by spectroscopic means. No hydrate without guest molecules has been found in nature. Thus, clathrates are stabilized by the weak attractive interactions between guest and water molecules. However, the guest species has some restrictions on its size. This arises from the fact that there are a limited number of cage types which encapsulate guest molecule without deviation of the hydrogen bond lengths and angles from the ideal. All of the cages are not necessarily dependent on the temperature and the pressure of the guest compound in equilibrium with clathrate hydrate.

The formation of a hydrate requires the following three conditions: 1) hydrate formation is favored by low temperature and high pressure; 2) presence of hydrate formers such as CH4, C2H4, CO2 and H2S; and 3) sufficient amount of water. There are three types of hydrates: Structure I, Structure II and Structure H.

Asphaltenes. The word asphaltene was coined by Boussingault in 1837 when he noticed that the distillation residue of some bitumen had asphalt-like properties. Asphaltenes are very large heterogeneous molecules with condensed aromatic nuclei. From an organic standpoint, they are large molecules comprised of polyaromatic and heterocyclic aromatic rings, with side branching. They originate with the complex molecule found in living plants and animals, which have only been partially broken down by the action of temperature and pressure over geologic time. They carry the bulk of the organic chemicals of crude oil such as sulfur, nitrogen, nickel and vanadium. They are not soluble in N-Heptane, but soluble in aromatic solvents such as toluene. All oils contain a certain amount of asphaltene. Asphaltenes only become a problem during production when they are unstable. They have a hydrogen-to-carbon mole ratio around 1.15, (wax=2) and density of approximately 1.3 g/ cm3.

Crude oils with unstable asphaltenes suffer from some severe operational problems most of which are fouling-related and affect valves, chokes, filters and tubing. Asphaltenes become unstable as pressure decreases and volume fraction of aliphatic components increases. If the aliphatic fraction of the oil reaches a threshold limit, then asphaltenes begin to flocculate and precipitate. This pressure is called the flocculation point. A checklist and decision making chart have been provided.

Scales. These are inorganic crystalline deposits that cake perforations, casing, production tubing, valves, chokes and flow lines. Scale deposition mainly depends on solubility change, temperature change, concentration of dissolved salts, minerals and gas and pH. Generally, an increase in temperature increases the solubility of water for mineral ions, but it is not necessary that all ions conform to the general trend. Calcium carbonate shows higher solubility between 25OC and 100OC than around 200OC. The presence of CO2 and H2S further complicates the carbonate’s solubility behavior. These are three mechanisms of scale formation.

Reduction in pressure or increase in temperature of brine leads to reduction in the solubility of salt (e.g. CaCO3). Mixing of water rich in barium, calcium and strontium cations with sulfate-rich seawater leads to sulfate scale precipitation. And the third mechanism is brine evaporation in high-pressure high-temperature wells. Typically, gas wells with very low water cut will see evaporation of brine in the stream and deposition of salt crystals as scale. Types of scale include carbonates, sulfates, sulfides, oxides, hydroxides, naturally occurring radioactives and naphtanates.

Emulsions. An emulsion is a suspension of small globules of one liquid in a second liquid with which the first will not mix. During production, the water and oil streams are subjected to mechanical agitation. Turbulent flow, pumps, valves and bends all serve as mixing elements of the oil and water phase. This may lead to the formation of a stable dispersion of small water droplets. This stable dispersion is also referred to as on emulsion. Emulsions can have a large effect on the pressure drop in a multiphase flow pipeline.

High water cut emulsions are usually strongly shear thinning and may even possess visco-elastic properties. The viscosity of water/ oil emulsion is always higher than that of the oil, even if the oil has a much larger viscosity than water. In fact, the viscosity of the emulsions may be dramatically higher, particularly at water cuts above 30%. Sometimes the point of maximum water uptake is referred to as the phase inversion point. This suggests that the water/ oil emulsions turn into an oil/water emulsion. Emulsions can be broken by heating or demulsifying chemical injection. Tight emulsions in production facilities are quite common, and these may cause difficulties in oil water separation.

Sand. This is composed of silica, SiO2 and feldspars. Clay may also be present as a minor constituent. Clay components include chlorite, iolite, kaolinite and smectite. These occur in the fine size fractions of a distribution. The size of a dehydrated clay particle is about 4 microns. Sands containing less than 5% clay are classed as clean and those with more than 5% weight as dirty. Produced sand may also be coated or mixed with barium sulphate and other scale compounds. These scale compounds can contain traces of naturally occurring radioactive elements sufficient to require special precautions in handling and disposal. Solids from limestone reservoirs would have a carbonate composition. Proppant compositions include silica (sand), bauxite, alumina and zirconia. Proppants may also be resin coated.

Behavior of sand in production equipment –e.g. its settling rate and erosiveness – depends on particle size distribution, density, shape and concentration. Sand concentration depends on several factors, including degree of rock consolidation, drawdown, production rate, downhole sand control system, rate of change of production, water cut and gas-to-oil ratio. Surges in sand production are likely following perforation operations and on breakthrough of injection water. Increasing hardness of formation is often indicative of greater cementation of sand grains and thus lowers sand production. Sand production levels usually increase with production rate but also depend on rate of change of production rate. A rapid increase in hydrocarbon production rate can produce an abnormally high sand rate which subsequently declines toward the previous level. In fracturing operations, propped fractures can result in back production of sand at rates over 100 times higher than normal. As a general rule of thumb, maintain velocities above a minimum velocity of 1.5 m/s to avoid sand settling in pipelines. Various options are listed in the decision-making chart.

Corrosion. Corrosion is characterized by material loss and localized thinning of the pipe wall and the process is electrochemical, requiring a corrosive environment for it to occur. The corrosion will be either general or localized pits. Various types of corrosion and mitigation strategies are discussed in the decision-making chart.

Waxes. The waxes basically consist of n- alkanes (n C17- n C43) which crystallize to form an interlocking structure of plates, needle or malformed crystals. Worldwide, one can distinguish about 1,500 varieties of crude oil of which 10-20% are considered to be waxy. Such a classification was based on the wax content of the crude and its pour point. Waxy crude oils exhibit non-newtonian behavior at temperatures below about 10oC above pour point. The wax can crystallize as the crude is cooled to form jelly or hard wax with melting points from near room temperature to over 100OC.

Wax has a density of around 0.8 g/cm3 and a heat capacity of 0.140 w/m.k. Under static conditions, a hard wax is formed, but if the crude is cooled while in motion, the apparent viscosity will increase but the materials remain fluid. Therefore, the rheological properties are functions of temperature, shear rate, shear stress and past history. Yield stress measures the ability of fluid to restart its flow after shutdown of the transportation system. The yield stress of oil, at a given temperature is defined as the shear stress required to initiate flow. It can thus be directly compared with the shear stress available or allowable in a pipeline.

The yield stress of waxy crudes is influenced by temperature history, shear history, aging and composition. Most waxy crude oil gels exhibit thixotropic or occasionally rheopectic behavior. (A fluid whose viscosity decreases with time at a given shear rate is called thixotropic. If the viscosity of a fluid increase with time at a given shear rate, the fluid is called rheopectic).

The temperature at which crystals first begin to form is called the cloud point. At temperatures below the cloud point, crystals begin to form and grow. Crystals may form either in the bulk fluid, forming particles that are transported along with the fluid or they may deposit on a cold surface where the crystals will build up and foul the surface. The first issue is gel formation and second issue is deposition. A crude oil gel forms when wax precipitates from the oil and forms a three dimensional structure spanning the pipe. This does not occur while the oil is flowing because the intermolecular structure is destroyed by shear forces as it is able to form.

However, when the oil stops flowing, wax particles will interact, join together and form a network resulting in a gel structure if enough wax is out of solution. IP 143 (SARA), true boiling point (TBP), simulated distillation (ASTM D 2887), and chromatographic analysis are a few of the methods that are used to characterize hydrocarbon fluids. In general, the amount of paraffin in oil decreases with the decreasing API gravity. A separate checklist and decision-making chart are provided.

Drag-reducing agents. By injecting the friction reducing additive, or DRA, the capacity of the single-phase crude pipeline system (i.e. liquid only) can be increased. Generally these are high molecular weight (1 to 10 million) polymers with very long chain molecules. When pipeline flow is turbulent, the cross section is divided into three regions: 1) laminar sublayer, 2) buffer region and 3) turbulent core.

The laminar layer tends to be stationary while the turbulent core is moving fastest. Because of a wide difference in velocities, the buffer region experiences turbulent eddies. This activity “draws down” the hydraulic energy of the stream and the upstream end gets additional back pressure. Drag reducers suppress turbulent eddies in buffer region and the hydraulic energy is better utilized in moving fluid instead of overcoming “random drag.” The normal achievable reduction in pressure drop for liquid system would be around 10% only. In cases where the oil/condensate is continuously liquid phase, then a hydrocarbon-soluble DRA will be selected (Poly Alpha Olefins). If water is the continuous phase, then a water-soluble DRA will be selected (Poly Acryl Amide). The general mechanism of DRA is reducing the turbulence.

As mentioned, a DRA works by reducing the turbulence by suppression of energy dissipating eddies/ currents/ wakes which normally develop near the pipe wall. DRA effect may be slowly reduced in the direction of flow due to the gradual breakdown of the long-chain molecule. While selecting a DRA the properties should be analyzed with respect to design conditions of the pipelines. Please see the decision-making chart.

Flow assurance conceptual design involves multidisciplinary integrated work which often requires cooperation and coordination among various disciplines/teams.

Authors’ note: Literature references are available from the authors.

Acknowledgement
The authors extend their special thanks to M. Dhakshnamoorthy, Senior Engineer (Pipeline and Piping), L&T-Gulf Pvt Ltd., for his invaluable help in drawing the decision-making flow sheet.

Download the authors’ checklists (PDF)

Authors
B. Chandragupthan is a senior engineer (process technologies) for Saipem India Projects Ltd., Chennai, India. Previously, he worked as a deputy manager (process dept.) with PL Engineering Ltd., Gurgaon, India. He holds a bachelor of technology degree (chemical engineering.) from the University of Madras and a master of technology in refining and petrochemical engineering from the University of Petroleum and Energy Studies, Dehradun, India. He can be reached at b.chandragupthan@gmail.com.

Girish Babu Nounchi is an assistant manager, pipeline and piping engineering, with L&T- Gulf Pvt Ltd., Faridabad, India. He holds a bachelor of engineering degree (mechanical engineering) from Andhra University and a master of technology degree in pipeline engineering from the University of Petroleum and Energy Studies, Dehradun, India. He can be reached at girishnounchi@gmail.com.