Summary Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient, and fluid properties. In this study, a new model for the prediction of single-phase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial-wax concentration might be different from the equilibrium-wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time - a process known as "aging." The effect of shear stripping may also be incorporated in the prediction. The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa U. Paraffin Deposition Projects, with two different oils: a black oil and a condensate. Even though some tuning is required for each type of oil, the new model is based on physical phenomena, reducing the empiricism of previous models. Introduction In oil production and transportation systems, when the fluid temperature drops below the wax-appearance temperature, the long-chain normal paraffins of the formula CnH2n+2 where n>20 will solidify and adhere to the pipe walls, if a radial heat flux to the surroundings exists. This phenomenon, known as "paraffin deposition," can cause a reduction in the effective flow area. Paraffin deposition can result in significant operational and remedial costs, reduced or deferred production, well shut-ins, and pipeline replacements and/or abandonment. It is imperative to properly identify the conditions for paraffin precipitation and to predict paraffin deposition rates for the design and optimization of oil- and gas-production systems, as well as to implement proper strategies for prevention and remediation. Understanding the paraffin deposition process under single-phase flow conditions is crucial to properly model the phenomena under both the single-phase and multiphase flow conditions encountered in oil-production systems. Model Enhancement One of the main limitations in the current Tulsa U. (TU) single-phase paraffin deposition model1 is the assumption of constant oil fraction in the deposit that the user is required to specify as an input parameter. It is also assumed that all the mass flux from the bulk fluid contributes to deposit growth, and no diffusion into the deposit is considered. The current model does not consider the aging effect on the deposition process. Singh et al.2 proposed a model that considers the diffusion of wax into the existing deposit. The boundary condition used at the deposit-fluid interface was that the diffusion flux at the interface is equal to the slope of the wax solubility curve in equilibrium with the deposit temperature gradient. In this thin film model, the wax fraction in the deposit changes with time, but it is uniform across the deposit. Also, Singh et al. did not consider any shear-stripping effects, as all of their tests were conducted under laminar flow conditions. The new model proposed in this paper is analogous to the Singh et al. model in the sense that it also considers that part of the bulk flux will contribute to new deposit growth, and the rest will be diffused into the existing deposit. The model considers a kinetic resistance for the diffusion into the deposit; therefore, the interfacial concentration might be different from the equilibrium concentration at the interface temperature. The kinetic resistance would be different for different oils. Also, the proposed model assumes that the deposit layer is immobile.

Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient and fluid properties. In this study, a new model for the prediction of single-phase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial wax concentration might be different from the equilibrium wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time, a process known as aging. The effect of shear stripping may also be incorporated in the prediction. The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa University Paraffin Deposition Projects with two different oils: a black oil and a condensate. Even though some tuning is required for each oil, the new model is based on physical phenomena, reducing the empiricism of previous models. Introduction In oil production and transportation systems, when the fluid temperature drops below the Wax Appearance Temperature (WAT), long chain normal paraffins of the formula CnH2n+2 where n>20 will solidify, and can adhere to the pipe walls if a radial heat flux to the surroundings exists. This phenomenon, known as paraffin deposition, can cause a reduction in the effective flow area. Paraffin deposition can result in significant operational and remedial costs, reduced or deferred production, well shut-ins, and pipeline replacements and/or abandonment. It is imperative to properly identify the conditions for paraffin precipitation and predict paraffin deposition rates for the design and optimization of oil and gas production systems, as well as to implement proper strategies for prevention and remediation. Understanding the paraffin deposition process under single-phase flow conditions is crucial to properly model the phenomena under both the single-phase and multiphase flow conditions encountered in oil production systems. Model Enhancement One of the main limitations in the current TU single-phase paraffin deposition model1 is the assumption of constant oil fraction in the deposit that the user is required to specify as an input parameter. It is also assumed that all the mass flux from the bulk fluid contributes to deposit growth, and no diffusion into the deposit is considered. The current model does not consider the aging effect on the deposition process. Singh et al.2 proposed a model that considers the diffusion of wax into the existing deposit. The boundary condition used at the deposit-fluid interface was that the diffusion flux at the interface is equal to the slope of the wax solubility curve in equilibrium with the deposit temperature gradient. In this thin film model, the wax fraction in the deposit changes with time, but is uniform across the deposit. Also, Singh et al. did not consider any shear stripping effects, since all of their tests were conducted under laminar flow conditions. The new model proposed in this paper is analogous to the Singh et al. model in the sense that it also considers that part of the bulk flux will contribute to new deposit growth and the rest will be diffused into the existing deposit. The model considers a kinetic resistance for the diffusion into the deposit; therefore, the interfacial concentration might be different from the equilibrium concentration at the interface temperature. The kinetic resistance would be different for different oils. Also, the proposed model assumes that the deposit layer is immobile.

An Oil reserve is discovered in a remote shallow water area offshore Africa, where the water depth is approximately 200 ft. The predicted production rate is approximately 500 BPD per well. The obtained oil samples indicate that the produced fluid has a high pour point (91°F) and a high wax appearance temperature (105°F). A dry tree completion is the planned option for this field. The wellhead flowing temperature (WHFT) is predicted to be below the wax appearance temperature (WAT) during normal flow without heating. Under certain specific field conditions, such as the development being considered, hot gas can be used as a means to maintain WHFT above the oil WAT and also be used as an artificial lift method to produce the low pressure / low temperature wells (LPLT). Economically, since the reserve is located remotely from gas market, the produced gas is "free." This paper describes the engineering evaluation of a hot gas lift design concept for a particular LPLT field. The hot gas lift method will avoid wax deposition, gelling and blockage problems in the wellbore. The wellbore thermal-hydraulic behavior is studied to optimize gas lift injection rates and temperature. Introduction Gas lift is a simple, reliable artificial lift method that is frequently used in offshore oil field developments1. It is one of the industry's first choices to develop low pressure fields, provided there is an adequate supply of injection gas. The gas after being injected into the casing-tubing annulus at the wellhead, enters the production tubing via a gas lift valve (GLV) situated in the gas lift mandrel (GLM). The gas injection entry point is designed such that the geothermal temperature is higher than the solid deposition temperature, in this case, WAT. One of the shortcomings of the conventional gas lift technique is that the injection gas would cool the production stream. Low temperature wells are particularly affected since the production temperature can be close to WAT. Typically, hot gas is not used to transfer heat energy because its heat capacity is low. However, with wellbore casing insulation, hot gas could heat production streams to maintain higher temperatures at the wellhead, possibly making certain marginal fields to produce. A schematic of a hot gas lift system is shown in Figure 1.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractInsulation and active heating options evaluated for transportation of waxy crude oil in an 8-inch flowline from a platform 10 miles offshore. Two bundled pipeline configurations are studied, and the results are compared with conventional pipe-in-pipe and a non-jacketed insulated pipe. The crude has a high pour point (PP, 91°F) and a high wax appearance temperature (WAT, 105°F).A solution is provided that allows the crude to stay above WAT. The non-jacketed pipe option is not thermally efficient; the pipe-in-pipe option can keep the crude oil warm during normal flow; but high storage capacity is required at the platform, which makes the solution impractical. The bundled pipeline configurations maintain the crude oil temperature above WAT thus avoiding waxing and gelling during steady state flow and during restart operations.Despite being more expensive, the bundled pipeline configuration proved to be the right solution for this particular field. The results of this study are applicable for evaluations of similar field developments.

In the oil and gas production industry, it is well known that formation of hydrate blockages can cause substantial economic impact in terms of deferred production and the costs of remediation. Considering these financial implications and to avoid any potential safety concerns during a hydrate remediation, most often operating companies design and operate fields on a hydrate management philosophy of complete avoidance of hydrate formation. In the last few years, however, a shift in the hydrate management philosophy is being observed as discussed in the publications of Creek et al., 2011 and Kinnari et al., 2015, to cite a few. Due to the developments shifting towards more extreme environments, hydrate management philosophy is shifting from complete avoidance to risk management. This paper discusses the evolution of hydrate management philosophy of a dry tree facility in the Gulf of Mexico. During steady state production, the fluids flow at temperatures outside the hydrate envelope. The hydrate management strategy following a shutdown is to displace (bullhead) the riser tubing with dead oil within the cooldown time (time required for the fluids to enter hydrate forming conditions after a shutdown). However, due to the dry tree configuration, low liquid rates and insulation performance, the cooldown time is short for these high water cut wells. Using gas lift to boost production further decreases the predicted cooldown time to less than an hour making it operationally difficult to complete hydrate safe out measures within the design cooldown time. A few tests conducted in the field to identify a realistic time available after shutdown, along with a few historical instances during which the hydrate safe out measures could not be completed within the cooldown time, have indicated that there exists a range of water cut (WC) and GOR (Gas to oil ratio) within which the system was restarted without a hydrate blockage. This paper describes how a combination of industry standard predictive tools coupled with field observations is shaping the hydrate management philosophy of this field, by operating within conditions that can form hydrates but do not lead to blockage. The paper also describes two hydrate blockage instances that occurred when the operating conditions were outside the identified hydrate blockage limit reinforcing that the WC and GOR of the fluids have a strong influence on the hydrate blockage risk.