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The wells in an oil field in East Venezuela have a bottomhole static temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in these wells. Currently, various formulations of mud acids, organics acids, and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms, the new sandstone acidizing systemreduces the multiple stages in traditional sandstone acidizing to one stage;minimizes precipitations by delayed and stabilized reaction mechanisms;provides homogeneous dissolution of formation;has a much lower emulsion and sludge tendency than conventional fluids as well as lower corrosion rate; andstimulates sandstone reservoirs at high temperature by effective damage removal and further matrix dissolution. Acid solubility, ion concentration, and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the formation core sample during the acid preflush. Additionally, mud acid shows further damage after the treatment. In contrast, the new fluid system shows consistent damage removal during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested. Introduction The oil field is located in Maracaibo, Venezuela. The BHST in wells ranges from 220 oF to 240oF. Most of the wells have numerous perforated intervals stretching up to 1000 ft (of which up to 500 ft is perforated). The mineralogy varies from interval to interval, with 4–16% CaCO3, 6–18% clays (mainly kaolinite), 5–10% feldspars, and siderites in some wells (2–5%). The reservoir pressure in zones ranges between 800 and 2500 psi and skin varies across the zones. The rock permeability varies from 1 mD to 200 mD among the zones. The main formation damage mechanisms were identified as fines migration (80–90% production decline after treatment) and CaCO3 scales, mainly due to loss of workover fluids. Currently, various formulations of mud acid, organic clay acid, and solvents are being used to treat these wells with mixed results. The new sandstone acidizing system is developed to effectively treat multi-layered high temperature (200–375oF) reservoirs with long production intervals and complex mineralogy. The benefits of the new sandstone acidizing fluid, which utilizes a novel chemistry, include simplified placement process (i.e., single stage), less precipitation tendency, reduced tubular and production equipment corrosion, and less exposure of hazardous fluids to personnel and the environment at the wellsite. These benefits ultimately lead to a high success rate of sandstone acidizing and sustained production increase from high temperature sandstone reservoirs. A comprehensive laboratory study, which includes acid solubility tests, X-Ray Diffraction (XRD) analysis, batch reaction kinetics, fines migration tests, core flow tests, was conducted on field cores to evaluate and compare the performance of the new sandstone acidizing system with current systems being used in the above oil field.

Summary Many studies have been completed concerning the evaluation of fracture height growth during hydraulic fracturing. While there are analytical solutions available to estimate vertical fracture growth, a more comprehensive solution requires the use of coupled geomechanics-reservoir simulators (GMRS) that could also fully incorporate the effects of fluid-flow into the analysis. This paper introduces results from a new coupled in-house GMRS to estimate the extent of vertical tensile regions developed in the sand interval that could break into adjacent shales during surfactant-polymer injection for a well located onshore Asia. The reservoir was treated as an elastic material and the injection zone was treated as a zone of higher permeability after the weakly consolidated formation reached a tensile stress state. The geomechanical information for the simulator was obtained from triaxial tests, well-logs and minifracs. Reservoir and fluid data were extracted from the in-house reservoir simulator model available for the field. A half unit of a seven-spot pattern was evaluated by using an unstructured grid, which provided more geometric flexibility. The results indicated that injection rates higher than 4000 B/D (0.0074 m3/s) combined with viscosities greater than 10 cp (0.01 Pa-s) will cause the fracture to break into the shales penetrating into the bottom sand. On the other hand, injection rates lower than 2000 B/D (0.0037 m3/s) were shown to be safe, even for the highest viscosity injection fluid tested, viz 30 cp (0.03 Pa-s). Viscosities greater than 20 cp (0.02 Pa-s) cause the injection fluid to break into adjacent sands if flow rates are above 2000 B/D (0.0037 m3/s). As expected, the higher the viscosity and injection rate, the higher the tendency of the fractures to grow out of containment. A chart with safe limits for surfactant-polymer injection was provided to the business unit to guide them in the design of new injectors and provide safe conditions for surfactant-polymer injection.

Planning and executing recompletions in low pressure reservoirs (less than 4 lbmjgal equivalent) present operators with several challenging conditions. These include the necessity to protect against formation.damage and fluid loss when using low density brines and well control when using foam as the completion fluid.Low density brines can be effectively used for workover operations in wells to be recompleted in a low pressure reservoir.However, because of the overbalanced condition that exists during workover operations, fluid loss must be controlled by spotting lost circulation pills.These pills can contribute to formation damage and can also affect the gravel placement unless they are effectively removed during the workover operation.In contrast, the formation can be more effectively protected by taking advantage of the low fluid leakoff characteristics and near-balanced pressure when a foam system of the required quality is used as the workover fluid.A workover program using foam as the workover fluid on wells completed in a low pressure, dry gas reservoir ( 3. 5 lbmjgal equivalent) was conducted offshoreLouisiana. This program included cleaning sand from the tubing andjor c~sing below the packer, reperforat1ng and gravel packing. A conventional foam system was used for cleaning the sand, and a stable foam system was used for well control. The 223 gravel placement was accomplished with a Xanthan polymer system. This paper will summarize the operational aspects related to the use of foam, the gravel packing operations and the production results after recompletion.

Texaco has completed three horizontal wells in actually drilled and completed, it was necessary shallow gas sands in the Gulf of Mexico. The to select the best suited completion assembly, producing sands in all these wells have relatively completion fluid and drilling fluid. high permeabilities and are unconsolidated. This paper discusses the process used to select the completion hardware, drilling fluids, and completion fluids for these wells. In addition, the