Summary Hydraulic fracturing has historically been a prime engineering tool for improving well producing rates, either by circumventing near-well damage or by stimulating well performance. This paper describes a somewhat new fracturing application where increasing rate was not the primary goal. In this case, the goal for fracturing was modification of the flow profile to allow a more uniform vertical production profile and thereby maximize sand-free rates over the perforated section of the reservoir. In best cases for such applications, this technique allows perforating of "weak" rock to be skipped, reduces risks of sand production, and allows greater wellbore drawdown through perforated intervals in more competent reservoir rock. This allows better long-term productivity and improved recovery and total project economics. In short, it was hoped that propped fractures would improve reservoir management of the Etive/ Rannoch formations in the Gullfaks field. Introduction The Gullfaks field, in the central part of the East Shetland basin in the northern North Sea, is operated by Statoil. The field was developed with three platforms and started production in Dec. 1986. Of more than 116 planned wells, 81 wells (including 6 subsea satellite wells) have been drilled. The field currently can produce about 600,000 BOPD, and estimated production life of the field is 20 years. The main drive mechanism is water injection. Predicted ultimate oil production from the field is 1,590 million bbl. About 465 million bbl was produced by Nov. 1993. Forecasted ultimate production represents 46% field recovery. Oil is produced from three major sandstone units: the Brent group, the Cook formation, and the Statfjord formation. The Etive/Rannoch formations of the Lower Brent group contain about 33% of mapped HCPV for the field. The reservoirs are overpressured, with an initial reservoir pressure of 4,495 psi at datum depth (6,070 ft below mean sea level) and 158°F. The shallow, highly porous sands are generally poorly consolidated. The oil is undersaturated, with a saturation pressure of about 3,550 psi, depending on formation depth and location.

fax 01-972-952-9435. AbstractIt is important to be able to have an overview of the well integrity at all times. Statoil, Norsk Hydro and Total E&P UK Ltd. therefore joined forces in a JIP with ExproSoft to develop a software application for data collection, handling and reporting of well integrity. The resulting software is called WIMS, short for Well Integrity Management System. A pilot version was installed and tested by the operators' spring 2007, prior to the release of the final version.WIMS enables a uniform and structured approach for describing the status and handling of well integrity issues throughout the production phase of a well. This paper discusses the philosophy behind how WIMS handles well integrity information from when the well completion is installed until the well is permanent abandoned. The well integrity data follows the well from it is new, and is continuously updated when a well leak or other well integrity derogations occur. To assist in leak diagnosis, risk assessment and defining corrective measures; test results, continuous pressure and temperature data, annuli top-up and bleed-off data is presented in WIMS. The paper also describes how information is aggregated from well level and summarized to give an overview of the well integrity status for any defined cluster of wells.WIMS is developed with the input and needs from three different operators, and the paper also includes a discussion of how WIMS will be used by the three operators.Apart from the need of systemized and easily communicated well integrity data, the success of WIMS is dependant on the implementation process. Very often the implementation process is neglected, and there are numerous examples of failed attempts at introducing new software in the oil and gas industry. The paper shares the experience from the evaluation and implementation of WIMS.

fax 01-972-952-9435. AbstractIt is important to be able to have an overview of the well integrity at all times. Statoil, Norsk Hydro and Total E&P UK Ltd. therefore joined forces in a JIP with ExproSoft to develop a software application for data collection, handling and reporting of well integrity. The resulting software is called WIMS, short for Well Integrity Management System. A pilot version was installed and tested by the operators' spring 2007, prior to the release of the final version.WIMS enables a uniform and structured approach for describing the status and handling of well integrity issues throughout the production phase of a well. This paper discusses the philosophy behind how WIMS handles well integrity information from when the well completion is installed until the well is permanent abandoned. The well integrity data follows the well from it is new, and is continuously updated when a well leak or other well integrity derogations occur. To assist in leak diagnosis, risk assessment and defining corrective measures; test results, continuous pressure and temperature data, annuli top-up and bleed-off data is presented in WIMS. The paper also describes how information is aggregated from well level and summarized to give an overview of the well integrity status for any defined cluster of wells.WIMS is developed with the input and needs from three different operators, and the paper also includes a discussion of how WIMS will be used by the three operators.Apart from the need of systemized and easily communicated well integrity data, the success of WIMS is dependant on the implementation process. Very often the implementation process is neglected, and there are numerous examples of failed attempts at introducing new software in the oil and gas industry. The paper shares the experience from the evaluation and implementation of WIMS.

This paper describes the planning, design, execution and results of massive fracture acidizing treatments in the Tommeliten Field, offshore Norway. The Tommeliten is a marginal field consisting of subsea completions. Difficulties in effectively stimulating the Tommeliten wells arise from numerous factors including the relatively soft and homogeneous nature of the chalk reservoir, large intervals requiring staged treatments, high treating pressures, high formation temperatures, and the logistics of performing the treatments via a semi-submersible drilling rig and stimulation vessel. Based on experience in other chalk formations, a general treatment program was formulated. Treatment design utilized multi-stages of viscous pad followed by acid and over flush. Fracture geometry was simulated by means of computer design programs. Extensive laboratory testing was then carried out to provide data for improving the program. As each well was treated the program was modified based upon information from pre-fracturing injection tests and the main treatment profiles. One and one-half years production data were available at the writing of this paper and form the basis for the productivity evaluation. INTRODUCTION The Tommeliten Field is situated in block 1/9 in the western part of the Ekofisk Area of the North Sea (Fig. 1). This field is operated by Statoil with Norske Fina and Norsk AGIP as partners. The field consists of two distinct and separate structures, Alpha and Gamma. Phase I of the Tommeliten project consisted of six wells in the Gamma structure. This project, a subsea development in water depth of 250 ft, is based on the use of existing infrastructure of the Ekofisk complexes. The six Gamma wells have been drilled through a single subsea template and are tied to the Edda platform, 7.5 miles to the northeast, via a subsea manifold. Drilling of the Tommeliten wells was described by Sunde.1 The subsea template has been described by Solheim.2 Completion and stimulation of these wells took place during the months of May-August 1988 and contractual gas deliveries commenced in early October 1988. Reserves in the Tommeliten Field are found in the Ekofisk and Tor formations, chalk sediments of the Tertiary and Upper Cretaceous Period (Fig. 2). The reservoir is a massive chalky limestone with high porosity and low matrix permeability, similar to other reservoirs in the Ekofisk Area. Combined thickness of the Ekofisk and Tor intervals ranges from 300 to 700 ft. Pressure and temperature at a depth of 10,168 ft mean sea level (MSL) are approximately 7,050 psi and 265°F.3 The gas/oil ratio was expected to be about 1,470 Sm3 /m3.4 Statoil discovered the Tommeliten field in 1976, but its relatively small size and a lack of realistic commercial outlet for the gas delayed development. One significant benefit of the long lead time between discovery and production is the extensive experience which has been gained regarding stimulation techniques for North Sea Chalks and specifically for Ekofisk Area wells. REVIEW OF STIMULATION TECHNIQUES Chalk reservoirs are an exploration objective in many parts of the world. Chalks typically have high porosity, however, due to their low permeability they are only marginally profitable unless they can be effectively stimulated.