As the frac/pack technology continues to evolve, there are a number of topics that need more understanding and improvement. Some of these are: The estimation of correct closure pressure, which in turn leads to evaluation of the correct fluid efficiency, and ultimately leads to the design of the slurry schedule. In addition, a proper fluid selection criterion is critical to the placement of highly conductive propped fracture wings via tip screenout. This paper describes the long strides that have been taken to address these areas. Special attention is given to skin data from build-up tests showing skin increasing with increase in kh. In essence the paper shows effective ways to lower the skin, and consequently increase production. This goal is accomplished by adjusting the design of the frac/pack slurry schedule to observation from field data and to numerical modeling of the fracturing process, and also, by considering the issues stated above. As a consequence, the paper shows that important steps to minimize the skin are to:Design the fracturing fluids to suit the character of the fractures in soft formations where cooldown, fluid velocities, and fluid exposure time are important.Use equilibrium method to fine-tune the closure pressure (and fluid efficiency) evaluation.Clean and pack the perforations not aligned with the fracture.Use diversion techniques to pack the entire reservoir.Evaluate the packing efficiency with bottomhole gauge data (temperature and pressure) and/or radioactive tracers. When these steps are meticulously followed, fracture performances with lower skins can be obtained as demonstrated in the case history. Introduction After more than one decade, the frac-packing technology has gradually established as one of the most widely used completion techniques for high permeability formations.1–3 In many fronts it is becoming a mature industry where, across the borders, service companies have comparable state of the art vessels, downhole tools, equipment, and fluids technology; and in other fronts, such as, intelligent completions, multiple zone production diagnosis, and damage repair, technology is continuously improving. Even with all these advancements, there is still room for improvements to achieve maximum well potential. For example, average production skins are higher than desired (Figure 1). Like in the sports arena, excellence comes through refining and perfecting the basic game principles; the core of this paper is to refine the use of existing technology with the aim of optimizing production. With this goal in mind, we present principles for refining the estimation of closure pressures, fluid efficiency, and perforation clean up. We also summarized some lessons learned that could prevent costly interventions. In-situ Stresses The estimation of the correct in-situ stress is important because it leads to the correct evaluation of other parameters that are critical to the design of the slurry schedule for a tip-screenout (TSO) treatment and prediction of fracture geometry. An inflection point on the pressure decline plot of a calibration test is a common method used to measure in-situ stress. However, in many cases the pressure decline plot shows inflection points not related to in-situ stresses but to other mechanisms like change in flow regime or gas kicks that could lead to the wrong estimate. In this section, we present application of a new method that facilitates the closure pick, known as the Equilibrium Step Rate Test (ESR). In addition, we present a field-derived correlation for deepwater wells that provides a reliable way to estimate in-situ stress.

The Otter field is the first "dual" electric submersible pump (ESP) completion in the U.K. sector of the North Sea in a subsea field development. This subsea development consists of three horizontal openhole oil producers and two cased-hole water injectors clustered around a production manifold and tieback, 21 km from the Eider host platform. Each oil producer has been able to deliver up to 20,000 BOPD since October 2002. Because a risk of sand production was identified during the life of the field, downhole sand control was deemed necessary.Well longevity has a major impact on the global-project economics. This meant that achieving and maintaining sand-free production through optimal completion design was critical to the overall success of the development.This paper describes the strategy adopted and the factors considered in the development of the sandface completion design for the field's life. The sand-control technique had to be decided upon while drilling the well, on the basis of the drill cuttings-particlesize analysis-oversmall particles would have lead to an openhole gravel pack. It appeared that correct geosteering was permitted to stay within a sand body that was adequate for standalone screen completion, which the authors consider the best option (i.e., in cost, risk, and efficiency) when applicable. The operational experience gained and lessons learned on the first well contributed to the design enhancements required for completion of the horizontal wells described in this paper.

The OTTER field is the first to use a "dual ESP" completion in a subsea field, the project was developed by TOTAL and its partner's in the Brent sand reservoir, in the UK North Sea sector. This development consists of three horizontal open hole oil producers and two cased hole water injectors, drilled from a combined drilling template and production manifold and tied-back to the EIDER host platform 21km away. Each oil producer can deliver up to 20,000 BOPD, the field has been on production since October 2002. A risk of sand production during the life of the field was identified, therefore downhole sand control was deemed necessary. Well longevity has a major impact on the global project economics. Achieving and maintaining sand free production through optimal completion design was therefore critical to the overall success of the development. This paper describes the strategy adopted and the factors considered in the development of the sandface completion optimised for the field life. Decisions on the sand control technique decisions were made while drilling the well based on cuttings particle size analysis: too small would have lead to open hole gravel pack. By eosteering the horizontal drain to stay within the most competent a sand body it would be possible to use a Stand Alone Screen completion, which was considered as the best option (cost, risk, and efficiency). The operationnal experience gained and lessons learnt on the first well contributed to the design enhancements required for completion of the following horizontal wells. Introduction The OTTER field lies in the Northern area of the Northern North Sea on the egde of the Viking Graben area and is located in UK blocks 210/15a and 210/20d (refer to figure 1). The field is operated by Total E&P UK PLC on behalf of the joint venture partners DANA Petroleum (E&P) Ltd, Esso Exploration and Production UK Ltd and Shell U.K. Exploration and Production (Shell Expro). The field (originally called Wendy) was discovered in 1977 by Philips Petroleum 210/15–2 well that was tested at 4746 bopd, however the field remained undevelopped until 2002 due to limited size of the discovery and the technical challenges involved. Fina Exploration acquired operatorship of the field in 1994 and a 3D seismic survey was performed. Interest in developing the field was renewed, and to prove reserves and well deliverability, a delineation well 210/15a-5 was drilled and tested in 1997. The results of this well were encouraging and a development screening study was launched. A further delineation well, 210/15a-6, was drilled in 2000 to confirm a field extension to the North prior to the launch of the development project. Development Description The development consists of three horizontal open hole oil production wells each equipped with dual ESP and two cased and perforated water injection wells to provide pressure support. The dual pump systems allow significant production acceleration and improved recovery, while retaining lift redundancy and operational flexibility. The subsea equipment comprises of a four slots drilling template with integral production manifold, which were installed prior to the start of the drilling operations. Water depth at template location is 184 m. The delineation well 210/15a-5 located 35 m from the main installation is tied to the template for use as a water injector. The manifold is tied back to the EIDER platform, operated by Shell Expro, at a distance of 21 km.