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.

Mesophase technology for wellbore cleanup and remediation in the drilling industry has been used in various oil fields to increase well productivity and injectivity. The majority of these applications include oil-based mud filter cake removal, nearwellbore remediation, and wellbore displacement. The openhole wells completed with standalone screens in deepwater tertiary formations offshore West Africa have benefited from previous knowledge and experiences accumulated by the operator and the service company in the application of mesophase technology in other fields. This paper discusses the field application of mesophase technology in several deepwater offshore fields in West Africa. Prior to the field application, the mesophase formulation was customized for the field conditions, such as temperature, fluid density, type of completion brine, and the specific oil-based mud. The customized formulation was evaluated to determine the regain of injection permeability, fluid compatibility, and the breakthrough time. Intensive tests were required to fine-tune the formulation to obtain the desired high injection permeability for the challenging field conditions. Results from the laboratory and description of the field application are discussed and presented in this paper. The field applications data proved that, after placement of the mesophase treatment in the wells, diffusion of the treatment produced: (1) break-up of blocking solids from the completion screens; (2) removal of filter-cake residues; and (3) water-wetting of all solid surfaces. This cleaning treatment gave very good results in the production and water-injection wells.

Any quantitative workflow, designed to constrain reservoir models to 3D/4D seismic data, must rely on petro-elastic modelling (or PEM), which relates fluid and rock properties to elastic ones. Various scales must be accounted for: laboratory cores and well logs, geological and seismic grids, fluid flow simulator models. The petro-elastic model is generally a fine-scale model ("pem"), defined and calibrated for each specific case against core and logs data. Aiming a 4D history matching workflow at the flow model scale, we then need to validate the use of the logs-scale calibrated "pem" at a larger scale, vertically and laterally. In this paper we proposed a methodology to define an upscaled "PEM" (new set of relationships valid at reservoir-scale), by tuning a fine-scale existing "pem", adjusting the most sensitive and relevant parameters, by an optimisation procedure. Some previous studies already addressed downscaling problems (from reservoir to geological/seismic scale), but no previous work has proposed any solution for an upscaled PEM. The main results of this study, using real field data, are the following:upscaling is necessary, depending on the degree of static and dynamic heterogeneity;the optimisation procedure is successful in calibrating a fine-scale "pem" to get a reservoir-scale "PEM";the procedure is sensitive to the Backus averaging parameters, which must be defined carefully;this workflow is performed at wells in this study, but could be extended to reservoir scale, when a fine-scale geological model is available Introduction This study was motivated by the use of 4D seismic data, in particular in History-Matching. One possible approach, consists of applying the matching loop at the elastic domain level and at the reservoir scale, making use of a petro-elastic model to convert fluid properties and static rock properties into simulated elastic properties. This was developed during the HUTS project [Ref. 1, 2, 3)]. Coupling such a rock physics module, or petro-elastic model (PEM) with fluid flow modelling, the simulated elastic parameters (impedances) can be predicted before and during production. This can then enable the changes in rock and fluid properties to be compared with the changes inferred from the seismic surveys, thus providing additional information for computer-aided history matching. Other studies [Ref. 4, 5] also propose similar quantitative work, each applying a different approach in terms of the objective function used to minimising the mismatch between ‘observed’ seismic and computed impedances (PEM), and/or domain scale. There are indeed various scales to be considered and accounted for within the above mentioned 4D history matching workflow, or any quantitative approach: laboratory cores and well logs, geological and seismic grids, fluid flow simulator models. Since the PEM is to be used for seismic modelling and history matching of reservoir models, it can be applied at any of these above-mentioned scales. Other authors [Ref. 6] propose the geological scale as the domain for the history matching, thereby simulating the PEM at the same scale as the geostatistical simulation grid, i.e. generating synthetic saturation/pressure with the fluid flow simulator, downscaling to the fine geological model scale and then computing the elastic properties.

Lead and Zinc sulphides have recently become a concern in some HP/HT gas fields. The Elgin/Franklin Field (Central Graben North Sea), started production early 2001. The wells produce a condensate-rich gas from the Fulmar and Pentland reservoirs, with initial temperature of 200 degC and pressure of 1100 bar. Mid-2002, the first Calcium Carbonate obstructions appeared downhole on several wells and resulted in a progressive production decrease. Moreover, lead and zinc sulphides were identified on well G6. The heavy scaling from its surface-controlled subsurface safety valve (SCSSV) to the Christmas Tree caused the well to be shut-in from end 2004 until an appropriate programme of remediation and prevention was implemented. Lead and zinc sulphides had not been predicted during the initial scaling studies. While several publications mention these on HP/HT fields, little information is available on downhole inhibitor squeeze. Scale removal lab studies included dissolution of the recovered scales and corrosion tests. A different fluid package was selected for downhole and SCSSV conditions. Scale remediation using downhole acid washes proved efficient by increasing wells production. The upper part of the completion on well G6 was cleared from scales by a coiled tubing operation in mid-2005 and the integrity of the SCSSV was restored. To prepare for scale prevention, a benchmarking of inhibitors from four suppliers was performed in a third party lab over a period of more than two years. Appropriate equipment was put in place and the methodology was optimised. The tests were conducted in anaerobic conditions with thermally aged chemicals. Two scale inhibitor squeezes were deployed, although progress is still to be made for "exotic" scale prevention. This paper presents the Elgin/Franklin scale-control strategy from a thorough fluids selection to the field deployments. Results and optimisation are discussed. Introduction Calcium Carbonate (CaCO3) is the most common "self-scaling" specie found in oil and gas fields. Scale deposition is a widespread problem that causes production deferment, necessitates costly intervention, and can compromise safety systems. The situation can be more severe in high-pressure, high-temperature (HP/HT) fields since the changes in pressure and temperature are potentially greater and because the formation water in such fields is often of very high salinity. Initial scale control philosophy. The Elgin/Franklin Field is a platform development in the Central Graben area of the North Sea's UK sector (Block 22/30b, 22/30c and 29/5b), approximately 240 kilometers East of Aberdeen. Production started in March 2001, from 10 wells. The Fulmar and Pentland reservoirs in Elgin/Franklin produce a retrograde condensate gas and are characterized by very harsh conditions - temperature close to 200°C, initial pressure up to 1100 bar - and a high salinity formation water, close to 300,000 mg/l. The hydrocarbons also contain around 3 mol% CO2, and traces of H2S in insufficient quantity to be measured in produced fluid. The potential for scale deposition - primarily sodium chloride (NaCl) and Calcium Carbonate (CaCO3) - was recognized early in the project phase. Preliminary studies were performed in 1995 and 2000, based on water samples taken during DST in 1991 and 1995. Initial scale prediction studies identified a low risk for calcium carbonate scaling in the upper tubing of wells with less than 100m3 of water per day. Of more initial concern was the NaCl, prone to forming not only in topsides, but also downhole, early in the field life, due to vaporisation of water when in small amount.

Near-wellbore formation damage and high mechanical skin is a concern on the deep water horizontal wells drilled and completed off the West Coast of Africa. Due to the typically unconsolidated sandstone reservoirs, sand control is essential, either Stand Alone Screens (SAS), or Open Hole Gravel Pack (OHGP) sandface completions are run to contain the sands. Although the drilling mud is replaced by sieved mud, and carefully controlled for solids, plugging can still occur through insufficient degradation of the filter cake. In addition, losses during the drilling of the drain and even the screen size vs. openhole diameter can also have a significant impact.Productivity impairment issues originally encountered on Rosa producer wells (Deep offshore Angola, Block 17) led to the development and testing of a unique micro-emulsion technology in 2006, for use with coiled tubing deployed remedial treatment inside the screens. The 'cake breaker' system, a stable blend of surfactant, acid and brine, was tailored for the mud system used, and designed for fast acting remedial treatment. The results of the Rosa intervention treatments proved successful and additional testing was carried out in 2007 / 2008 to benchmark the tailored system to other products on the market. The tailored system remained the system of choice and the same remedial treatment formulation was applied on some of the earlier Dalia wells (producer & injector). Treatment results were positive, and have improved further still by optimizing the formulation.Preventative treatments have also been developed, using various deployment methods. The evolution has been towards a displacement of the mud in the open hole / screen annulus, prior to displacing inside the screens. The results have been mixed however, with the remedial treatments generally proving more effective than the preventative treatments. This paper looks at the experience gained on the deep water horizontal wells in Block 17 off the west coast of Angola, namely the Rosa, Girasol, Dalia and more recently the Pazflor field. The differences in results are evaluated and the various methods and lessons learnt are presented.