TX 7508-33836, U.S.A., fax 01-214-952-9435. AbstractThis paper presents the results of successful applications of inorganic gels to control water production. In naturally fractured reservoirs a case study with hostile high temperatures (260-31 0 °F) found in the Cretaceous and Jurassic dolomitic limestone's of the south east of Mexico is presented together with a water exclusion case from the tertiary sandstones. Importance of gel penetration and selective placement to considerably delay the water percolation to upper intervals in hydraulically communicated intervals is discussed. Included are alternatives for control of gel invasion from the high conductivity fracture network to the tight matrix. Finally, the paper presents a brief discussion of the future of water control in naturally fractured reservoirs.

Formation damage, tubing plugging and plugged production equipment caused by the deposition of organic deposits and sludge are inherent in many workover and stimulation operations around the world. This paper describes the methodology followed to improve production through adequate stimulation treatments and control of the organic and sludge deposition existing in the south-east of Mexico. In fact, this is a recurring problem that has existed for many years severely affecting oil production. Evaluation of the results and conclusions derived at different stages of the analysis are discussed. The benefits of emulsifying the acid with an aromatic(external phase), are also presented including the key factor of the iron reducing agent in a ferric iron environment in addition to the required iron sequestering agent. Results of stimulations performed in the area are discussed including well performance months after treatments. Introduction Organic deposits and sludge problems are increasing in the petroleum industry. Their precipitation is a problem that has existed for many years in the south east of Mexico, severely affecting oil production. Oil production in the south east of Mexico is distributed between the tertiary sands, the Cretaceous and Jurassic dolomitic limestone's. These last two are found in the 5,000 to 6,200 meters (m) range with temperatures in the 125–155°C. The reservoir considered in this paper is characterized by natural fractures with a 35° API sludge tendency crude containing asphaltenes in the 10–15% range, paraffin in the 15–20% (High Molecular Weight) and 2-5% (Low Molecular Weight) causing routine deposition in the production equipment, tubing and formation. Until recently, the main approach for resolving the severe deposition of these organics has been remedial; i.e., routine injection of appropriate chemicals to dissolve the deposits. In fact, a good portion of the wells have a0.95 cm capillary tubing which is run with the production tubing for continuous injection of both asphaltene and paraffin dispersants to alleviate the problem. However, the persisting asphaltene-sludge precipitation problem was in need for another approach.

Oil reservoir depletion resulting from commercial exploitation of mature fields has increased the frequency of special drilling conditions caused by low formation pressures that can lead to massive drilling fluid losses. Several of these challenges have been addressed by cementation engineering, specifically applied to the production casing. Because of these conditions, the Antonio J. Bermúdez basin has been constantly evolving with regard to cementing technology as well as drilling fluids concerns in an effort to effectively obtain long term zonal isolation. Application of cementation engineering for production casing in development fields has resulted in the need for low-density slurries that can rapidly develop compressive strength. Furthermore, improvement in rock mechanics understanding using formation-evaluation technologies, has positioned cementation engineering as a technical discipline focused on application of solutions encompassing the entire life of the well. As a result, for example, the concepts of elasticity and durability have become important for cementation engineering, which is now moving far beyond the traditional application of hydraulic principles for slurry design. This paper describes the evolution and maturing of the Antonio J. Bermúdez Basin during the past ten years and the changes in design and execution of cementing operations as a result of new challenges in oil-based and water-based mud environments as well as the introduction of under-balanced drilling methods. Introduction The Antonio J. Bermúdez complex is located in southern Mexico in the states of Tabasco and Chiapas (Fig. 1). The reservoir has a history of exploitation dating from the 1930s, producing from multiple zones of fractured and vugular carbonates derived from geological events that caused the Jurassic Gulf of Mexico opening in the late Triassic to late Jurassic periods. With the onset of the break up of Pangaea (Fig. 2), where redbeds, volcanics, and salt were deposited in a system of rifts, the marine deposition environment is the source of most oil and gas reservoir rocks (carbonates and dolomites) in the Bermúdez complex, massive erosion caused a diversified high- to low-permeability distribution, along the breccia trend. This complex composed basically by Samaria-Iride giant oilfields, Oxiacaque and Cunduacan, principally exploits reservoirs of light crude oil contained in limestone deposits and naturally fractured limestone and dolomite. Typical reservoir characteristics are shown in Table 1. As a consequence of their exploitation, these deposits have experienced, during their life cycle, different phases that have created cementing and engineering challenges. Starting with a highly pressurized reservoir that required normal density slurries to the ultra-light density foamed slurries with densities as low as 0.6 sg required in some areas today. Not only does the pressure change in the reservoir, but also well depth and geometry, bottomhole flowing pressure, lifting technique from natural to gas lift, water-oil contact, fluid viscosity as it moves closer to the bubble point, stimulation, completion, and workover techniques and pressure testing methods. All of these changing factors are directly related to the evolution of cementing engineering to efficiently exploit this reservoir, applying a methodology that studies the sequences of events over the life of the Bermúdez complex oil wells, integrating new knowledge and applying new technologies, correcting and adjusting previous knowledge, gathering observable, empirical, and measurable evidence, focusing not only in cement slurry design as was done in the past but an integrated engineering process to understand the challenges that change over time and address them in consequence, including key performance indicators, well challenges, objectives, best practices, scorecards, material selections, testing, job planning, execution, QA/QC, and post-job evaluation, integrating a proven methodology that, if applied, will consistently help lead to obtaining an effective annular seal over the life of the well.

With the discovery of new fields becoming less common and the need to maximize economic recovery in mature fields, operators are trending towards rig-less intervention work to reduce cost and delays to production related to traditional workover rig interventions. With its field complexities, from low bottom hole pressure (BHP) to high temperature/high pressure (HT/HP) reservoirs, and from consolidated sandstone to naturally highly fractured carbonates, and large producing intervals in various flow units with active aquifers, southern Mexico poses a highly significant challenge for rig-less intervention in water control and zonal isolation to assure placement and accuracy of treatment fluids. This paper discusses the implementations and results of two case histories in which a cost-effective application involving coiled tubing and inflatable packer systems were used for water control in a high water cut producing well and for well abandonment of a newly completed well. The utilization of coiled tubing combined with the inflatable packer is able to precisely deliver the treatment fluids to the zone of interest while the production tubing remains in place, which enhances timely and cost effective intervention solutions1 when compared to workover rig operations. Case 1 presents the water control application using a coiled tubing inflatable packer system in combination with an organic crosslinked polymer gel, and micro-fine cement slurry for a naturally fractured carbonate reservoir in southern Mexico. The result of this innovative rig-less approach exceeded the operator's expectations. The case history well was producing 815 BOPD and 5.2 MMSCFD with a water cut of 77%. After the water control treatment with the coiled tubing inflatable packer system, organic crosslinked polymer gel and micro-fine cement slurry, the well was producing 1,459 BOPD and 5.15 MMSCFD with a water cut of 0%. Case 2 demonstrates a newly completed well with production tubing and packer already set and the well producing with high water cut from an open-hole completion. By using the inflatable packer system through coiled tubing and squeezing cement slurry to abandon the open-hole, a new interval could be perforated and exploited in just 28 hours; in contrast, conventional abandonment with a rig can take up to 10 days.