The indiCat ions of cement deterioration at one of the greatest gas condensate fields in Pannonian basin (Croatia) was the motivation for research study carried out in order to investigate the possible involved mechanism of impairment. After almost 15 years of hydrocarbon production form naturally fractured carbonates, some wells begun to suffer of plugging across the perforated zone with unidentified debris, which was accompanied with water cut increase. This paper describes the laboratory evaluation of the actual environmental down hole impact (high reservoir temperature, BHST>180°C, sour gas: 22% CO2 and 150 ppm H2S) to the cement, as well as debris identification. The work indicated that oilwell cement under hostile down hole conditions after long-term exposure could be deteriorated loosing of compressive strength and its integrity. The dominant mechanism of cement deterioration is caused by CO2 corrosion process in the form of carbonic acid leaching. The CBL log data verified the cement disintegration behind 7-in. casing after 15 years of well production period. Introduction This paper is based on comparison of field, laboratory and published data in order to clarify the problem of impairment of well productivity at one of the greatest gas-condensate fields located in SW Pannonian basin (Drava River Depression) Croatia. More of 15 years of production history period for several wells (producing from naturally fractured carbonates) was characterized with some anomalies in terms of sharp water cut increase accompanied with building of an unidentified debris across the perforated zone. In order to investigate the occurred phenomena the research study was carried out judging the hypothesis about the cement deterioration as a cause of production failure. The conceivable mechanism of impairment was addressed to a long-term exposure of cement to the high temperature (BHST=180°C) and brine with sour gas (>20% CO2, 150 ppm H2S) environment. The problem of potential oilwell cement deterioration across the perforated zone, associated with various physico-chemical processes during, in most cases, decades of well service life was just sporadically considered in published petroleum engineering literature. The deterioration of neat Portland cement at temperature above 120°C has been known for many years. Same reports are suggesting original primary cement deterioration due to long-term contact to a particular formation water 1, especially at elevated (150–300°C) temperatures2,3,4. Studies on existing wellbore cement systems durability under geothermal conditions5,6,7 (BHT>250°C) verified that they may be deteriorated (loosing compressive strength and becoming permeable) in relatively short period of time6. The literature contains the detailed well documented information (based mostly on CO2 -EOR flooding studies) about carbonic acid corrosion in oil well cements3,8,9 as a dominant chemical process in wet CO2 environment—resulting with loss of compressive strength and structural integrity of cement sheath. This process, known as cement carbonation8,9 seemed to be the most likely the cause of cement deterioration in the studied particular case because of high CO2 content in production fluid gas-laden water and high reservoir temperature.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally bullhead water control consists of the placement of water-soluble chemicals without mechanically isolating oil layers. In order to be successful, bullhead treatments should block water-bearing layers without affecting the permeability of the oil-bearing layers too much. This paper reports an experimental investigation of an innovative water shutoff chemical deemed suitable to accomplish this task. The chemical is soluble in oil without any reaction, and is transferred into and reacts with water to form a stable gel. Core flow experiments consisting mostly of the injection of either oil or water in cores containing the chemical dissolved in oil were performed to investigate the ability of the gel to reduce water permeability while maintaining oil permeability. To ensure that the results are relevant for designing field applications, the experiments were performed under conditions encountered in various sandstone reservoirs in the North Sea, Croatia and other regions. Permeabilities and temperature ranging from 100 to 300 mD and 70-90 0 C were therefore considered in this study. The influence of the other physical parameters, such as viscosity, concentration of active chemical in oil chemical, injection rate, etc., was also investigated.

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Presented in this paper is a novel technique of hydraulic fracture azimuth determination. Full size oriented cores, retrieved after microfracturing, were scanned using X-ray computed tomography (CT) to evaluate the fractures. The SEM/EDAX analysis was applied to confirm the presence of barite particles from drilling mud inside hydraulically induced fractures. The study, performed on core samples from the same sandstone formation of two adjacent fields, showed the good agreement of fracture azimuth data, obtained from CT analysis. Postfrac well production history indicates a significant hydrocarbon productivity increase, without interference to surrounding wells. Introduction Orientation of hydraulically induced fractures has a significant impact on final results of hydraulic fracturing operations. Knowledge of hydraulic fracture orientation can be useful in many reservoir applications. Hydraulic fracture azimuth prediction becomes important in terms of improving recovery efficiency in case of producing wells, or optimizing the areal sweep efficiency in case of water flooding or EOR applications using injection wells. When designing the injection pattern and selecting optimum well locations, fracture azimuth should not be ignored. For waterflooding producing wells located perpendicular to the fracture direction will experience better areal sweep efficiency, than wells, situated parallel to the fracture direction. On the other hand, if fracture orientation can not be predicted, and spacing of wells is less than the designed propped fracture length - the wing of fracture can aim to the neighboring well, causing the failure of both wells. Also, if geological condition cause favorable fracture direction, the wing of fracture can reach the hydraulically isolated part of the reservoir, making it recoverable. A number of techniques and methods for mapping or predicting fracture orientation can be found in literature. These can be summarized as:active fracturing techniques (tiltmeter arrays, triaxial borehole seismic),openhole logging techniques (borehole elongation orientation, television camera, sonic televiewers, impression packers), andpredictive oriented core techniques (strain relaxation, compressional-wave velocity, thermal expansion, differential strain curve, fracture point load test or residual stress measurement). Although each of them under proper conditions can give more or less accurate and reliable results, each has limitations. In this paper, a new approach to indirect fracture azimuth measurement, based on oriented core analysis is described. The method involves microfracturing technique (Fig. 1) and X-ray CT scanning of oriented cores. During drilling, just after entering a zone of interest for future stimulation by hydraulic fracturing, the drilling process is temporarily interrupted and microfrac job, using relatively small volume of water base - barite weighted mud is performed. This is followed by coring operation and 3 to 10 m of full diameter oriented core is taken from the bottom of the well. The drilling procedure is then continued. Conventional core analysis is performed by visual inspection or by the use of goniometer to characterize fractures, if found on the core surface. X-ray computed tomography is used for visualization and investigation of fractures inside the rock body. Consecutive CT scanning of oriented core (Fig. 2), is made by taking axial cross sections subsequently reconstructed as tomogram images. Since the core orientation during scanning is known and fixed, fracture azimuth is easily determined (see Fig. 3). Analysis of tomogram series furnishes data on fracture growth and position in the core. Hydraulically made fractures can be filled with mud used for microfrac operation. The presence of solid particles, particularly high density barite, can be easily detected in CT tomograms, to distinguish hydraulically initiated fractures from naturally generated ones. Also, the traces of microfrac fluid can be analyzed after location and detection in the fracture by CT scanning, using the other analytical methods, such as SEM/EDAX or chemical analysis of selected rock specimens. Using the data from tomograms, 3-D reconstruction of hydraulically initiated fracture was made. P. 69

Current offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single pumping operation, improving efficiency and adding additional savings to the process. Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks. To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously. This novel multistage fracturing system combined with polymer-free viscoelastic surfactant fluid system prepared with seawater was applied in the World for the first time. Results indicate a sustained increased production. Introduction The Lebada Vest field was discovered in 1984 and put on production nine years later. This field is situated in the Black Sea, ~95 km offshore Romania. Since then, numerous vertical oil and gas wells were drilled and completed. The wells were produced initially in natural flow and later equipped with gas lift to enhance ultimate hydrocarbon recovery. The target reservoir is a Cretaceous-age formation located at depths of ~1,900-m true vertical depth (TVD) composed of varying shale, sandstone, and carbonate content layers. The laminated pay zone is generally formed by streaks with average permeability of 0.8 md. Reservoir rock porosity ranges between 15% and 22%. Bottomhole static temperature (BHST) is 93°C and bottomhole static pressure (BHSP) at ~1,850 m true vertical depth sub sea (TVDSS) is ~220 bars. To increase the hydrocarbons recovery, operating company decided to drill a horizontal well and target an un-drained part of the reservoir. Furthermore, to achieve greater efficiency in offshore operations and after evaluating completion options, including open hole, cemented liner with perforations, and slotted liner, Operating company decided to complete the well openhole and equip it with a permanent completion system that enabled the placement of multiple fracturing treatments (Barba and Shook 2004). Later, it was also determined that by using a novel Visco-Elastic Surfactant-based (VES) fluid, the entire operation could be performed in a single sequence, achieving additional savings in time and related costs.