An asphaltene threat has been identified in production wells located in a Gulf of Mexico (GOM) deepwater field. After production started from different reservoirs and the operating conditions for some of the wells reached the asphaltene precipitation onset, solid deposits were detected at different points in the production system, which caused production deferrals, disturbed the operating strategy of the field, and increased the operational expenditure. To remediate asphaltene deposition in deepwater subsea wells, a rig-less remediation costs up to $0.12 million (MM); a well intervention that requires a rig costs approximately $20 MM, and a vessel-based pumping remediation costs about $5 MM. These costs do not include the impact of production deferrals.A plan was developed to acquire and interpret the required information to properly understand and manage the asphaltene threat. The methodology includes:This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and lay out the aspects to be considered in the mitigation of the negative impact of asphaltene thread in the field development plan.
The world's natural gas proven reserves show enormous clean burning energy resources that call for its effective and efficient utilization. These gas resources, exceeding 6000 trillion cubic feet (TCF), currently represent a significant proportion of the energy equivalence of proven oil reserves. With over sixty (60) percent of such gas reserves located too far from potential markets, there is need to evaluate the prospective economics of promising technologies for the monetization of these stranded gas reserves. The main focus of this paper is the economics of the chemical conversion of natural gas to synthetic liquid fuels, favored by recent advances in Fischer-Tropsch (F-T) synthesis techniques, welcomed shift-to-liquid fuel transportation operations, and increased demand for clean burning diesel fuels. The value of this emerging technology will be the ability to turn natural gas reserves, currently too remote from the market, into high-quality premium products that could be transported as liquid fuels. The effect of capital expenditures (CAPEX), annual operating expenditures (OPEX), product price and various tax schemes on the rate of return (ROR), pay out time (POT) and the net present value (NPV) is investigated to access the economic viability of GTL plants. The range of CAPEX utilized is based on the production of one barrel of hydrocarbon liquid per day (BLPD) whereas the OPEX are expressed as percentages of CAPEX. Also, a construction period of three years is considered, while a 10% net-back on product sales is incorporated to account for the cost of natural gas feedstock. Monte-Carlo simulation is utilized to run sensitivity analysis, incorporating the probabilistic approach, to generate insightful scenarios on the project economics. The results (measures of profitability and their certainty bands) are analyzed and presented in tables, histograms and charts for a 100, 000 BLPD GTL plant. Introduction A significant proportion of the growth gas reserves seen in recent years is stranded gas, i.e. gas which is remote from markets and often in hostile environments. Simultaneously, there is a decisive trend in the utilization of gas relative to other fossil fuels. Natural gas has been steadily winning market share from coal, and it is currently overtaking coal in usage worldwide. The above trends have spawned the development and commercialization of a range of technologies that are directed at monetizing stranded gas reserves. Notably, gas utilization technologies are being considered as the key to realizing the full potential of most stranded natural gas as a source of Energy1,2. These technologies offer the promise of economically linking these remote gas assets to profitable markets. One of these technologies which is the main focus of this work involves the chemical conversion of Natural gas to Liquid or Gas-to-Liquid Technology. The fundamental problem hindering any significant monetization of most natural gas resources has been their transportation from remote fields to available world gas markets.
fax 01-972-952-9435. AbstractThe world's natural gas proven reserves show enormous clean burning energy resources that call for its effective and efficient utilization. These gas resources, exceeding 6000 trillion cubic feet (TCF), currently represent a significant proportion of the energy equivalence of proven oil reserves. With over sixty (60) percent of such gas reserves located too far from potential markets, there is need to evaluate the prospective economics of promising technologies for the monetization of these stranded gas reserves. The main focus of this paper is the economics of the chemical conversion of natural gas to synthetic liquid fuels, favored by recent advances in Fischer-Tropsch (F-T) synthesis techniques, welcomed shift-to-liquid fuel transportation operations, and increased demand for clean burning diesel fuels. The value of this emerging technology will be the ability to turn natural gas reserves, currently too remote from the market, into high-quality premium products that could be transported as liquid fuels.The effect of capital expenditures (CAPEX), annual operating expenditures (OPEX), product price and various tax schemes on the rate of return (ROR), pay out time (POT) and the net present value (NPV) is investigated to access the economic viability of GTL plants. The range of CAPEX utilized is based on the production of one barrel of hydrocarbon liquid per day (BLPD) whereas the OPEX are expressed as percentages of CAPEX. Also, a construction period of three years is considered, while a 10% net-back on product sales is incorporated to account for the cost of natural gas feedstock. Monte-Carlo simulation is utilized to run sensitivity analysis, incorporating the probabilistic approach, to generate insightful scenarios on the project economics. The results (measures of profitability and their certainty bands) are analyzed and presented in tables, histograms and charts for a 100, 000 BLPD GTL plant.
Biopolymers present non-toxic and degradable fluids that have been used extensively in reservoir drill-in fluids (RDF) to drill through reservoir rocks in oil and gas wells. Their numerous advantages, such as viscosity enhancement, filtration control, flocculation prevention, friction pressure reduction during turbulent flow conditions and shale stabilization amongst others have made them indispensable in oilfield applications. At the same time, the inherent formation damage as a result of the polymer molecules settling or being adsorbed on or into the reservoir rock pore spaces has been an area of concern to the industry. On the other hand, surfactant based fluid (SBF) systems typically leave little residue or formation damage compared to biopolymer systems, thereby gaining acceptance as RDF's. Low interfacial tension existing between SBF's and the produced or injected fluids is one of the major criteria for this reduction in formation damage. However, SBF has much higher fluid leak-off at reservoir conditions than wall-building biopolymer fluids, which has significantly limited their use in the industry.In this paper, several blends of a SBF or visco-elastic surfactant (VES) and a water soluble biopolymer, welan gum have been used to develop a SBF-biopolymer fluid system based upon compatibility, rheological and visco-elastic behavior. The study was performed by characterizing biopolymer-VES fluid systems for their ability to retain their rheological and visco-elastic properties at elevated temperatures. Data analysis showed that the blend captures the merits of the individual fluid systems, as well as reduction in overall cost as compared to using a SBF mud by itself. Blends consisting of higher concentrations of welan gum showed good thermal stability and retention of viscosity at elevated temperature. Hence, cost reduction is achieved in the amount of SBF utilized. Also, the results of surface tension measurements showed that the binary system exhibited values much lower than welan gum fluid, and about the same as the SBF. Filter press tests results showed the blends to have a lesser fluid loss. Other potential applications of this binary system are also discussed.
The challenge of theoretical and numerical studies of annular fluid flow with varying eccentricity is mainly due to the required coordinate systems. Computational fluid dynamics (CFD) modeling provides the state-of-the-art approach of investigating fluid flow in such complex geometries. In this study, results from a series of numerical simulations for the fully developed laminar flow of non-Newtonian power law fluids in concentric and eccentric annular geometries are used to investigate the effect of eccentricity, flow behavior index, and diameter ratio (ratio of the outer diameter of the inner tubing to the inner diameter of the outer tubing) on axial friction pressure losses. The friction pressure gradients predicted by the CFD simulations were verified by comparing with the published studies and flow data from a field scale experimental set-up. At a constant flow rate, it is confirmed that frictional pressure losses are decreased with increasing eccentricity. A good agreement was obtained with the Haciislamoglu et al. correlation, and the results of this study, especially at low values of eccentricity. At very high eccentricities, data from the CFD model yields lower friction pressure compared to Haciislamoglu et al. correlation. Haciislamoglu et al. type expression is obtained, incorporating the improved data of this study. Next, this paper presents the results of an experimental study carried out to investigate friction pressure behavior of drag reducing polymer solutions, flowing turbulently through an eccentric annulus. The experimental set-up includes 30 ft of 3½-in. x 2 3/8-in., 200 ft of 3½-in. x 1¾-in., 69 ft of 5½-in. x 4-in., and 79 ft of 5-in. x 3½-in. fully eccentric annuli. Data analysis enabled the development of a new correlation using fluids apparent viscosity at 511 sec-1, generalized Reynolds number, and diameter ratio, all of which can be easily determined in the field, as independent variables. These new correlations for laminar and turbulent flow of drag reducing polymer solutions present an improvement to existing correlations, and also permit undemanding hydraulic program calculations for varying annular configurations.
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