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The use of foams for gas floods conformance control attracts a renewed interest in recent years. Nowadays, despite the low oil price environment, some foam EOR projects remain active both at lab and pilot scale. Indeed, such applications have the potential to not only improve the oil rate, but may also reduce costs associated with gas injection and cycling. In other words, foam can increase gas injection efficiency both in terms of oil production and of gas consumption. In this paper, we describe the design of a dedicated foaming formulation and its application in a CO2 foam pilot in a CO2 flood in the US Gulf Coast. The main hurdle for formulation design was the use of a high salinity and hardness production water for chemicals injection. Our experimental approach to overcome this challenge was based on successive steps, comprising automated solubility evaluation of multi-component formulations, adsorption measurements, foam stability evaluation and finally corefloods in reservoir conditions. Following this lab work, we carried out the foam injection pilot on a 40 acre, 6-well flood pattern consisting of three injectors and six producers. Conformance rather than indepth mobility control was targeted, and a relatively low foam volume representing 1% pore volume of the pattern was thus injected. The treatment was applied as three alternating slugs of aqueous foaming solution and CO2 over a period of four months, with the aim of generating foam in-situ in the near- wellbore area. Strong foam formation in the near-wellbore was evidenced by a strong drop in CO2 injectivity after each surfactant slug. Injectivity then slowly recovered, with a slower recovery as a function of the slug number, indicative of foam propagation deeper in the reservoir. Injection logs showed an efficient diversion of CO2 from thief zones to previously poorly swept reservoir intervals. On the production side, although much less CO2 was injected, oil rate was relatively constant, exhibiting little decline. We interpret this as a consequence of the injected CO2 flooding new reservoir zones with higher residual oil saturation. Overall, the strong decrease in CO2 consumption at a relatively constant oil rate translates into a noticeable increase of the injected CO2 efficiency. This paper describes the formulation design and the foam pilot implementation in challenging conditions, in particular with regard to salinity and hardness of the available injection water. It qualifies foam as a straightforward, low risk conformance method. Indeed, besides potential increases in oil rate, the enhancement of CO2 injection efficiency demonstrates the success of this application.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe cementation of any casing string is an integral part of well construction. The main objective of primary cementing is to provide complete and permanent annular isolation from mechanical and chemical stresses during drilling and production stages of the life of the well.Through tubing rotary drilling (TTRD) technology presents its own challenges to cementing design. The management of the equivalent circulating density (ECD), typically at its highest levels during the final stages of the cement slurry displacement, is a critical parameter of the fluids design process. The use of bi-centre drilling bit design, which achieves a larger open hole size than the pass-through diameter, introduces centralization difficulties and add complexity to the removal of the drilling mud prior to cementing.The accepted cementation approach for TTRD wells is to formulate low rheological fluids such that, maximum advantage can be taken from the annular velocities for mud removal efficiency.By challenging the common design practices a design was proposed that combined low and high rheology fluid properties to achieve the objectives set out for the cementing operation of the 2 7/8 inch liner.

Approximately 50% of all installations in the UK offshore sector are small steel jacket structures that are normally unmanned. These platforms often have severe limitations on the permissible lift weight of temporary well servicing equipment. During a study into the extent of this problem, it was observed that a significant proportion of gas production is reliant on wells producing via these normally unmanned installations, and that production from this source has declined dramatically in recent years. When compared to manned installations where (intervention is easier and therefore assumed more frequent), production decline is less severe. An operator identified a production enhancement opportunity on an unmanned installation in the North Sea UK Sector. The well needed extensive intervention in order to be brought back to production using coiled tubing (CT). Due to the restricted crane capacity (less than 7.5 ton) on the platform, a conventional CT package could not be lifted on board. Through a collaborative project, an existing CT equipment package was modified to be lifted within this weight limit. A boat spooling technique was used to install the CT string onboard the platform without using a crane as it was much heavier than the crane limit. Throughout the equipment modification project, the principles of efficient rig up and optimized fast, safe working where applied. The installation of this equipment on the platform was conducted quickly and easily, validating this approach and improving on previous experiences significantly. This paper demonstrates how conventional equipment can be adapted to meet the challenges faced with platforms considered inaccessible to perform CT interventions. Introduction The application of Coiled Tubing (CT) interventions within the offshore environment has matured significantly over several decades. However, the use of CT to perform intervention services on small steel offshore platforms is a relatively uncommon practice. These installations create a nique challenge for access to perform intervention operations as many are classified as Normally Unmanned Installations (NUI). Despite wells being constructed with a standalone completion design philosophy (similar to subsea wells), often intervention is required in many wells, particularly as North Sea infrastructure ages and matures. The need for CT operations is being realised more frequently by operators of wells on these types of installation in the North Sea. These NUIs usually have severe limitations on size of deck area to work with, limited provision for personnel accommodation, and low crane lift capacity. To compound the problem, many of these platforms are getting older, and their cranes are being de-rated. Crane capacity is a function of boom angle. In bad weather conditions it is often necessary to extend the boom to avoid the risk of the supply vessel hitting the platform. Bad weather also affects the maximum safe lift possible from an offshore platform. Crane replacement, however, is difficult and very expensive. As a consequence of these access restrictions, cost effective CT intervention is rarely performed on United Kingdom Continental Shelf NUIs. In the past, the only effective method of accessing wells on NUIs has been to use a drilling jack up rig or workover jack up rig. The availability of workover rigs suitable for this work has been extremely limited and the cost of using a drilling jack-up has become prohibitively expensive in the past five years.

This paper describes innovative small diameter electrical pump systems which can be installed through tubing or casing using cable deployment or coil tubing deployment, eliminating the need for a rig during pump installation and retrieval operations in the field. The capability is being developed for 10 bbl/day to 10,000 bbl/day pumping systems.The underlying, new technology which enables small, high force dense pumping systems is permanent magnet technology, including novel permanent magnet motors and permanent magnet transmissions. This technology, which has been under development for the last 3 years, exists for pumps so small they can be retrofitted though 2 3/8" production tubing (low volume pumping) and larger diameter for high volume pumping. Integrated downhole sensors provide valuable data for production management and condition monitoring of the downhole pumping system. Systems utilizing these technologies are currently undergoing qualification testing in preparation for field trials late 2012/ 2013. Numerous rigless intervention opportunities can be realised in most oilfield environments as the technology enables a key industry transition from a workover activity to an intervention activity for installation and retrieval of pumping systems. Conveyance of pumping systems is decoupled from jointed pipe rigs, offering significant opportunities for operational cost savings and production uptime. For example, pumps can be installed and maintained from a riserless light well intervention vessel in a subsea well, or in a well on a normally unmanned offshore installation, or installed in a remote land location without a using rig.