The exploitation of a thin depleted gas reservoir in Sharjah presented a series of challenges. Economic considerations made it imperative that the operations should achieve optimum productivity. This necessitated horizontal wells drilled to exploit the vertical fractures and high permeability streaks within the reservoir coupled with a drilling fluid designed to preserve maximum production potential. The drilling fluid needed to:
have low density
have low invasion characteristics
be stable at 285 F (141 C) BHT
be easily dissolved from the formation face in order to facilitate a low pressure acid wash stimulation.
To select the optimum, fluid laboratory tests were carried out on three systems:
80/20 oil/water ratio invert emulsion
water based drill-in system.
Diesel was selected as the external phase in the two oil- based fluids tested. The laboratory work involved formation damage tests on cores from this field, simulated acid washes and determination of radial filtrate invasion distances. The all-oil fluid had the best performance with respect to minimising formation damage. In addition, rheological and lubricity properties were in the range required for good drilling, hole cleaning ability etc.
To date 4 wells have been drilled with this system, of which 3 are multi-lateral. In each case laboratory predictions have been borne out. The excellent hole cleaning, borehole stability, mud lubricity and absence of incidences of stuck pipe have enabled much greater horizontal displacements than those planned to be achieved. The predicted nondamaging behavior of this fluid has been confirmed in the field by the absence of significant damage or skin effects compared to other, earlier field wells which did not have the benefit of the new technology.
This paper deals with the technology involved in the fluid and the field operations and with the team approach adopted in the process of identifying and using the optimum fluid.
The following is a case history documenting the evaluation and selection of the drilling fluid used to drill the horizontal section through the Shuaiba section of the Thamama of a well in the Sajaa field. Comparison of the laboratory predictions with the actual performance of the drilling fluid during the drilling phase has been made.
Three drilling fluid candidates were recommended:
A water-based fluid comprising sized calcium carbonate bridging material with a blend of thixotropic polysaccharide polymers and polymeric filtration control additives (BARADRlL-N).
A specially formulated 100% oil drilling fluid that has been developed to control formation damage caused by conventional drilling and coring operations without altering native wettability (COREDRIL-N).
A classical 80120 diesel based invert emulsion drilling fluid (INVERMUL).
Drilling fluid evaluation was performed by the Amoco Production Technology Group, Formation Damage Team based in Tulsa. The fluid samples were prepared by Baroid Drilling Fluids in Houston.
These fluids were evaluated using the Dynamic Formation Damage (DFD) tester against native cores obtained from previous wells the area.
Testing Methodology. Core plugs were cut 1 inch in diameter and as long as possible to a maximum length of 4 inches. Table 1 is an inventory of the cores available for testing. X ray diffraction of Core A showed a high purity calcium carbonate. P. 337^