This work was carried to study Guar gum as a Hydraulic Fracturing carrier fluid and also to look at how we can properly optimize the properties of the Guar gum to achieve a very efficient carrier fluid that will suspend proppant into the formation.The problems that necessitated the carrying out of this project was that over the years there has been failure in hydraulic fracturing operation due to shear degradation of Guar carrier fluid, high temperature denaturing of Guar carrier fluid and insoluble residue formation from Guar carrier fluid which may cause formation damage.These problems where studied using shear history simulator, high temperature and high pressure viscometer and also API RP39 procedure which gives the guideline for testing carrier fluid. It was established through this work that proper optimizing of the guar concentration can be used to control the shear degradation and temperature effect on the Guar carrier fluid. Also with the application of necessary additives, the Guar carried fluid can be used in a very high temperature formation.
This research work outlines the main results of the shale instability study with respect to shale/ fluid interaction mechanisms, and also analyses the shale strength properties. An approach was undertaken to develop a better understanding of the effects of using polymer drilling fluid on the shale mechanical properties and how to optimize its performance. Wellbore stability in shale is very much influenced by the type of drilling fluid used, here the problems observed were, borehole fluid invasion into the shale, increase in potential pipe sticking, swelling/hydration of shale which results in high level of non-production time (NPT). Different drilling fluids were analyzed for their effects on shale strength. Emphasis here was on the mechanical properties of the shale samples after exposed to different drilling fluids for 24hours. The mud which maintains high compressive strength of the shale is the most preferred (optimum) selection. The shale sample exposed to the polymer drilling fluid shows the lowest strength, from the stress-strain curve. The use of KCl brine in drilling fluids is based on its shale inhibition characteristics as it is thought that the k+ ion provides additional attraction among the clay platelets due to its size and charge. However the shale loses most part of its strength when exposed to the modified polymer drilling muds combined with 5% KCl, 7%, 10% KCl respectively. One of the possible reasons is Kaolinite in the shale. The shale samples will keep more of its original strength when exposed to the modified polymer drilling muds combined with chemical agents with plugging ability to pore throat and micro-fracture. The shale sample exposed to polymer drilling fluid with 10%Nacl, 5% Physical sealing agent and 10% Chemical agent A1 (rich in silica) exhibit the highest strength. From the result of the experiment the drilling fluid density has been reduced immensely, thus the new mud system improves the wellbore stability and keeps the shale formation stable.
Maintaining stability between shale-mud interaction is a key factor towards improving safety and drilling efficiency while minimizing costs associated with drilling and production operations. The use of conventional Water Base Mud in drilling shale formation results in the adsorption of water associated with the drilling mud by the shale. Depending on the shale type, water adsorption may lead to various reactions such as swelling, cuttings dispersion, and increase in pore pressure creating wellbore instability to varying degrees. This research provides information on shale characterization of two Wells, A and B in Niger/delta region Nigeria and proposes the development of inhibitive Water based drilling fluids for the shale samples. It also provide results of the shale mineralogy, native moisture content, total organic carbon content, cation exchange capacity and the adsorption isotherm of the shale samples. From the analysis, the X-Ray Diffraction (XRD) results indicate that the shales are dominant of kaolinite. The result of the CEC falls within the Kaolinites group of 3 Meq/100g -10 Meq/100g according to Boulding and Ginn (2003). Polymeric fluids composed of varying Polymer/salt (KCl, NaCl and CaCl 2 ) concentrations was prepared and evaluated for the shales samples using dispersion test. The result of the analysis was used to design a mud selection template for drilling through shales. Recommendations for improving shale stability were described, based on the current understanding of shale stability.
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