The Cambridge Minnelusa field alkaline-surfactant-polymer ͑ASP͒ flood was an economic and technical success, with ultimate incremental oil of 1,143,000 bbl at a cost of $2.42 per barrel. This success was due to an integrated approach of the application, including: reservoir engineering and geologic studies, laboratory chemical system design, numerical simulation, facilities design, and ongoing monitoring. This paper discusses how each of these was used in the design and evaluation of the Cambridge ASP project.

fax 01-972-952-9435. AbstractDuring the drilling and completion of the Huldra field in the North Sea, high temperature and high pressure conditions were expected and encountered in the reservoir section. The difference between the pore pressure and the fracturing pressure is small. Cesium formate had been evaluated as a potential drilling and completion fluid, but technical hurdles could not be completely addressed in time for the first well. As a result of well control problems occurring in the first well, with barite sag in the oil based drilling fluid as a contributing factor, it was necessary to use a drilling fluid with insignificant potential for sag. For the first time worldwide the cesium formate brine was chosen as a drilling fluid. This fluid could be delivered solids free with densities up to 2.2 s.g. The required down hole density in the well was 1.91 s.g. At the same time it was necessary to have as little contribution to the equivalent circulating density (ECD) from the flow as possible.The paper describes how the cesium formate brine was used successfully as a drilling and completion fluid. The effect of the fluid on well control, hole cleaning, rate of penetration (ROP), torque/friction, ECD, formation damage, casing wear and hole stability are covered. The paper also describes actions required to minimize losses of this very expensive fluid.The challenges acquiring adequate formations logs while drilling are also described. Finally, the use of cesium formate brine during the completing of the wells with open hole sand screens is outlined.

Monovalent formate brines were first introduced into the oilfield environment in the early-1990's, in response to the industry demand for better drilling and completion fluids to meet the increasingly complex technical challenges posed by modern well construction practices. After years of rigorous field-testing, in a variety of demanding well construction operations, the formate brines are now acknowledged to be probably the best foundation for any modern high performance drilling and completion fluid. The formate brines are currently having their greatest impact as the primary components of HT/HP reservoir drilling and completion fluid formulations. A number of field and laboratory tests have indicated that when formate-based formulations are used as reservoir drilling-in and completion fluids they appear to cause less formation damage than some other conventional fluid formulations, and consequently they are often seen to have a beneficial effect on well productivity. Up until now, however, little of this important information has found its way into the public domain. It has been common practice for a number of the major multinational oil companies to contract a specialist formation damage prediction company to carry out laboratory-scale formation damage tests with formate brines before using these fluids in their well constructions operations. This paper draws together the results of a significant number of these tests carried out by the specialist laboratory using formate-based fluids passed through real reservoir core materials for realistic time periods and under realistic reservoir conditions. As well as providing a unique insight into the interaction between formate brines and a range of reservoir core materials and reservoir fluid types under simulated downhole conditions, this paper also outlines the methodology developed to ensure that the formation damage tests carried out with formate brines are not influenced by laboratory artefacts. The conclusion of the paper is that a significant number of laboratory results, obtained under test conditions closely simulating reservoir conditions, tend to lend support to the growing perception that formate brines have valuable formation damage control properties that can be exploited to improve well productivity prospects in even the most demanding environments. Introduction Brines are used by the oil industry in a range of well construction operations, most commonly to create dense low-solids fluids for application in reservoir sections. A key driver for using brines in these applications has been the need to maintain well control while trying to minimise reservoir formation damage from solids invasion. Traditionally these oilfield brines have been based on halide (chloride or bromide) salts. Unfortunately the halide-based brines were never purpose-designed for oilfield applications and they have a number of performance deficiencies that become amplified as the brine density requirement is raised. Nevertheless, in the unsophisticated well construction environments that have existed in many parts of the world until relatively recently it has been possible for operators to somehow live with these deficiencies, albeit at some present or future financial cost. In recent years it has been clear that the traditional halide-based brines could no longer hope to meet the technical challenges of the increasingly complex and extreme well constructions that were being attempted to reduce field development costs and to increase production. In addition to the technical challenges that the traditional halide brines have been facing they have also been coming under pressure from the Health, Safety and Environmental lobbies. The use of halide-based brines in onshore environments has always been a concern anyway, given the toxicity of halides to aquatic life and all other non-marine organisms, and it can be expected that the legislation controlling the onshore application of halide brines will become more and more stringent.

This paper was prepared for presentation at the 1999 SPE Rocky Mountain Regional Meeting held in Gillette, Wyoming, 15–18 May 1999.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractDrilling and completion fluids based on cesium formate brines were selected by Statoil for use in the development of the high pressure high temperature Kvitebjørn field. Cesium formate brine was selected primarily to minimize well control problems and maximize well productivity. These important benefits had been recognized by Statoil in previous HPHT drilling and completion operations over the past 5 years. The use of the same fluid system for both drilling and completion gives the additional benefits of simplified operations, reduced waste, and elimination of fluid incompatibility problems.The challenge on the Kvitebjørn field was to drill long deviated well paths through significant sequences of shales into reservoirs with pressures of up to 81 MPa (11,700 psi) and temperatures up to 155°C (311°F). So far the cesium formate brine has enabled the successful drilling, completion, and logging of 7 high angle HPHT production wells on Kvitebjørn, two completed with a cemented perforated liner and five with sand screens.Additionally, an extended-reach exploration well was drilled from the Kvitebjørn platform to the Valemon structure. The 705 m (2,313 ft) long reservoir section of this 7,380 m (24,213 ft) long well with an inclination of 69°, was successfully drilled with the same cesium formate fluid system.In all these wells the cesium formate brine system once again demonstrated clear performance benefits such as very low ECDs, moderate to high ROPs, good hole-cleaning, and excellent wellbore stability while logging. Quick, trouble-free, safe, and robust completion operations were also accomplished, and the wells that have been put on production show high production rates with low skin.Full open-hole formation evaluation of the Kvitebjørn reservoir has been carried out with LWD tools. The evaluation has been aided by the development of a novel logging interpretation solution for a LWD density tool, in which the extremely high photoelectric effect of cesium-rich filtrate plays a vital role. Using photoelectric factor and bulk density data, combined with resistivity measurements from both the LWD drill pass and the ream pass, produces a very reliable and consistent net reservoir definition. The final interpretation result matches the core porosity from different lithologies in 3 different wells.Cesium formate brine has helped Statoil to achieve a remarkable record of zero well control incidents in all 15 HPHT drilling operations and 20 HPHT completion operations in the Kvitebjørn, Kristin, and Huldra fields over a period of 5 years.