Calcium naphthenate deposition is among the most challenging obstacles to high production regularity for oilfields where acidic crude oils are produced. Until now it has generally been acknowledged that the deposit is made up of calcium soaps of the naphthenic acids in the crude oil, though with a slight overrepresentation of the lighter acids. In this paper, however, we demonstrate that this is not the case. Through a combination of several analytical techniques - the most important being Potentiometric Titration, LC/MS, NMR, and VPO - the ARN acid has been identified as the dominating constituent of these deposits. The ARN acid is a family of 4-protic carboxylic acids containing 4 - 8 unsaturated sites (rings) in the hydrocarbon skeleton with mole weights in the range 1227–1235 g/mol. The mole weight of the homologous ARN acids series are 1227, 1229, 1231, 1233, 1235 (basic structures) + n×14 (n = number of additional CH[2]-groups in hydrocarbon skeleton).The ARN acid with mole weight 1231 has C[80]H[142]O[8] as empirical formula. The present paper describes the different analytical methods leading to the ARN acid discovery. Furthermore it discusses possible ARN structures and methods for quantitative ARN detection in crude oils. The ARN acid has proved to be the main component in naphthenate deposit from oilfields offshore Norway, Great Britain, China and West Africa.The implications of the discovery to current calcium naphthenate treating strategies will be briefly discussed. Introduction An increasing share of the oilfields found and developed around the world falls in the category "high-TAN crudes", i.e. contains significant amounts of carboxylic (mainly naphthenic) acids. Producing and refining high-TAN crude oils introduces a number of problems, among which calcium naphthenate deposition in process facilities is the most serious production issue.[1–4] The mechanistic understanding of calcium naphthenate deposition is still very limited, though. It is generally acknowledged that a reaction takes place between naphthenic acids in the oil and calcium ions in the water. The reaction product, calcium naphthenate, is basically insoluble in either of the phases and, hence, precipitates out and accumulates at the oil/water interface. Although this simple model describes the naphthenate deposition phenomenon nicely, it doesn't give any clue as to why the acids in the deposit do not resemble the acids in the crude oil (Mediaas et al.[5] have titrated acids isolated from a calcium naphthenate deposit sample and from the corresponding crude oil to show that the average mole weight of the former is significantly lower than that of the acids in the crude oil; 330 and 430 g/mol, respectively). Furthermore, in some cases, it takes only a few parts per million of a naphthenate inhibitor to suppress naphthenate deposition from oil and water containing 2 wt% naphthenic acids and 0.1 wt% calcium, respectively.[1] Together, these observations indicate that some rigid selection criteria direct which naphthenic acids are active in the naphthenate deposition process. These are nothing but field observations confirming laboratory experiments showing that high pH (~10 or higher) and high reactant concentrations are needed for detectable amounts of ordinary organic (including naphthenic) acids to deposit as calcium salts.[2] ConocoPhillips and Statoil have cooperated for several years to unravel the fundamental secrets of calcium naphthenate deposition. Our working hypothesis has been that the reason for the above described "discrepancies" between the model and field- and laboratory observations is that one or more specific structural elements need to be present in a naphthenic acid in order to render it receptive to deposition upon contact with calcium-containing water at pH ~6. The objective has been to identify structural keys that enable naphthenic acids to deposit as calcium naphthenate under production conditions. The first fruit of this cooperation - the identification of the ARN acid as a prerequisite for calcium naphthenate deposition - was presented at the ACS National Meeting in August 2004.[6] In this paper we will elaborate somewhat more on the ARN acid discovery before we present our present ideas regarding the structure of the ARN acid.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSelecting the components of fluids for reservoir drilling and completion can require extensive laboratory work to determine the most compatible fluid. Well temperatures in excess of 300°F (150°C) create additional challenges, as the additives required to give water-based reservoir drilling fluids the rheological and fluid-loss characteristics needed to successfully drill and complete long horizontal wells degrade at such elevated temperatures. In addition, supplying the necessary additives to a drilling operation in a remote location can be a major logistical burden, leading to a compromise in the fluid formulation.The Belanak field lies off the coast of Indonesia in the Natuna Sea. The reservoir temperature is high (315°F), and the reservoir sections are drilled horizontally, typically between 3,500 and 4,500 ft and often feature particularly tortuous well paths. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control.Six wells were drilled using the sodium formate-based reservoir drilling and completion fluids. The particle size distribution and concentration of the calcium carbonate bridging solids were monitored closely while drilling to ensure that filter cake quality was not compromised. A chelating agent-based breaker was used to break down the filter cake prior to the onset of production.The laboratory work required to optimize the fluids for this project had to take into account not only the requirements for the best fluid technically, but also the effect of the limitations created by working in a remote location. Considerations included minimum loading of calcium carbonate required to deposit a clean, high-quality filter cake and the effect of mixing brine for the reservoir drilling fluid or completion using seawater in case of a shortage of drill water.Fluid testing carried out in the laboratory included drilling performance at temperature, fluid compatibilities, bridging solids optimization, scale inhibition testing, and breaker selection. The fluid selected was based on sodium formatethe first application of a formate-based fluid in Indonesia.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSelecting the components of fluids for reservoir drilling and completion can require extensive laboratory work to determine the most compatible fluid. Well temperatures in excess of 300°F (150°C) create additional challenges, as the additives required to give water-based reservoir drilling fluids the rheological and fluid-loss characteristics needed to successfully drill and complete long horizontal wells degrade at such elevated temperatures. In addition, supplying the necessary additives to a drilling operation in a remote location can be a major logistical burden, leading to a compromise in the fluid formulation.The Belanak field lies off the coast of Indonesia in the Natuna Sea. The reservoir temperature is high (315°F), and the reservoir sections are drilled horizontally, typically between 3,500 and 4,500 ft and often feature particularly tortuous well paths. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control.Six wells were drilled using the sodium formate-based reservoir drilling and completion fluids. The particle size distribution and concentration of the calcium carbonate bridging solids were monitored closely while drilling to ensure that filter cake quality was not compromised. A chelating agent-based breaker was used to break down the filter cake prior to the onset of production.The laboratory work required to optimize the fluids for this project had to take into account not only the requirements for the best fluid technically, but also the effect of the limitations created by working in a remote location. Considerations included minimum loading of calcium carbonate required to deposit a clean, high-quality filter cake and the effect of mixing brine for the reservoir drilling fluid or completion using seawater in case of a shortage of drill water.Fluid testing carried out in the laboratory included drilling performance at temperature, fluid compatibilities, bridging solids optimization, scale inhibition testing, and breaker selection. The fluid selected was based on sodium formatethe first application of a formate-based fluid in Indonesia.

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Hearn, D.D.,* ARCO Oil and Gas Co.; Blount, C.G.,* and Hightower, C.M.,* ARCO Alaska Inc.; Coleman, D.R., Exxon Co. U.S.A.; Carlberg, B.L., retired; Wolf, N.O., Conoco Inc.; Clayton, C.K., Nalco Chemical Co.; Blevins, B.A., Turner, J.M., Knight, R.M., and Nethers, J., Xytec;Eatwell, W.D., Camco Inc.; Craig, D.R., McClintock, P., and Krause, L., Damson Oil Corp.; Andrew, J.H.,* and Hall, J.W., Conoco Inc.; and Hamouda, A.A., Phillips Petroleum Co. Norway Phillips Petroleum Co. Norway *SPE Members The Innovative Technology in Producing Operations Forum is designed to allow the discussion of and dissemination of information about technical innovations and solutions in production engineering that are of immediate practical use but do not warrant a full-scale paper. Each subject is presented in a five to eight minute period with a discussion period of seven to ten minutes. A wide range of subjects is encompassed in the session. Abstracts of the presentations follow. presentations follow. I. Successful Application of Coiled Tubing Underreamers by D.D. Hearn, Arco Oil and Gas Co.; C.G.Blount and C.M. Hightower, Arco Alaska Inc. This is an overview of the evolutionary development, the testing, and the application of a coiled tubing system capable of underreaming cement, scale, or fill below production tubing. Using downhole motors, this system performs cleanout operations that normally require rig workovers. Recent jobs successfully completed at Prudhoe Bay have shown order of magnitude cost reductions over conventional operations. This project was conceived as part of an effort to lower workover costs through the innovative use of coiled tubing. The goal was to assemble a system capable of underreaming below production tubing using coiled tubing units available on the North Slope. Not only would such a system reduce direct cost, it would eliminate possible formation damage encountered when killing a well. To have the greatest utility in Prudhoe Bay wells, the system had to be capable of passing through a 3.725 inch restriction in the production tubing and of underreaming either 7 inch or 9-5/8 inch casing. Work on coiled tubing underreaming began in 1984 as part a coiled tubing cement squeeze program. The part a coiled tubing cement squeeze program. The underreamer design was derived from a casing cutter, and though it was not reliable enough for general field application, it showed the potential and feasibility of the operation. An alternate method for removing cement during the squeeze operation lowered the priority for continued underreamer development, and little work was done in the area until spring of 1987. The market was surveyed for improvements in underreamer and motor design, and a test program was begun to evaluate the various components and how well they worked together. Test targets constructed at Arco's laboratory facilities simulated cased wells cemented from target depth, past the 3.725 inch XN nipple, and up into the tailpipe. The design goal was a system to clean cement from the tailpipe and nipple then open and clean cement from the casing. Available motor/underreamer combinations tested in the initial 1987 trials were unable to do this reliably. Typical problems were a lack of torque, erratic extension and retraction of cutting blades, and excessive vibration and wear. Potentially damaging vibration was a persistent problem. The underreamers were developed primarily for workover rigs and snubbing units, and had difficulty with the higher speed of even the slowest downhole motors. This testing showed the critical importance centering and fully supporting the underreamer has in controlling vibration, and that two blades cannot provide adequate support. provide adequate support. Using the best features of two blade underreamers currently on the market, new designs were developed with improved lateral support. One approach was to use three blades in place of two. Another approach was to add a second pair of blades just above the first and rotated 90 deg. The first pair cuts the cement and supports the underreamer in one direction while the second pair is only to provide support in the other lateral direction. P. 737